advanced h s and co removal technologies for...

Advanced H2 S and CO2 Removal Technologies for Synthesis Gases

>

Howard S. Meyer, R&D Director Shaojun (James) Zhou, Senior Engineer

Dennis Leppin, Senior Institute Engineer>

Gas Technology Institute Des Plaines, IL USA

May 2010

Advanced H2S and CO2 Removal Technologies for Synthesis Gases 2

INDIANA UTILITY REGULATORY COMMISSION JUNE 15, 2005 E-Gas Technology for Coal Gasificationhttp://www.narucpartnerships.org/Presentations/Albania/June05/Site%20visits/Terre_Haute_Wabbash_Coal_Gasification_Plant.pdf#search=%22egas%20gasification%22

Partial Gasification Schematic

CO2


Clean Syngas Targets

Contaminant Maximum After Cleanup

H2

S 50 ppbw

NH3 0.1 vol%

HCl 1 ppm

Hg 5 ppbw

Se 0.2 ppm

As 5 ppb

Cd 30 ppb

CO2 10% of CO2 produced

Advanced H2S and CO2 Removal Technologies for Synthesis Gases 44Advanced H2S and CO2 Removal Technologies for Synthesis Gases

Technology Outline


UCSRP-HP Process Development


UC Sulfur Recovery ProcessUC Sulfur Recovery Process

>Multi-contaminant removal process>Compound column at temperatures

─

above the sulfur melting point of 247°F (119°C) ─

below the polymerization temperature of 310°F (154°C)

>In the bottom half of tower, HCl, NH3

, and trace heavy metals (Hg, As, Se and Cd ) are removed

>In top half, H2

S reacts with injected excess SO2 in a catalyzed solvent circulating in counter-current or co-current manner


MultiMulti--Contaminant Cleanup Contaminant Cleanup ConceptConcept

NH4

Cl, (NH4

)2

Se, AsS, CdS, HgS

DEG, H2

O, NH3

, H2

S

DEG(Section A)

DGM + Catalyst (Section B)

SO2

Added

Partially Clean Syngas:

H2

S, COS, & NH3

H2

S & COS removedNH3, SO2

Clean SyngasDGM + Catalyst

SO2

and NH3

Depleted

Dirty Syngas:H2

S, COS, HCl, NH3

, As, Cd, Hg, Se

Includes immiscible liquid sulfur, NH3

, SO22 H

2S +

SO

2

3S +

2 H

2O


Degradation/Stability

29% H2

; 41% CO; 16% N2

; 11% CO2

; 7651ppm H2

S

1% SO2

in Balance Nitrogen


>

1,000 hour test>

Sulfur purity at 99.2% •

Major consumer purity specs 99.5-99.9%

>

2.3% of DEG/solvent degraded to tetraglyme•

Less volatile product

•

H2

S more soluble in tetraglyme•

Viscosity versus solubility

>

25% of catalyst (3-pyridyl carbinol) at 0.2% by weight of solution broke down to 3-

methylpyridine and 4-formylpyridine. •

Did not appear to effect reactivity.

>

COS formed at 35 ppm

Degradation/Stability Results


Multicontaminant Removal


Mercury Removal

05000

10000

15000200002500030000

350004000045000

0 1000 2000 3000 4000 5000 6000 7000

Time, sec

Hg

Con

cent

ratio

n,ng

/m 3

.

95% Mercury Removal with DEG as solvent


Bench-scale Unit


Summary of Results

>Elemental sulfur 99.2% close to target w/o processing

>Mercury removal to less than 0.2 ppb>Catalyst is active after 1000 hour test >Corrosion rates very low for carbon steel>50% H2

Se & 33% AsH3

removed in single stage scrub


Morphysorb® Syngas Treating Process


Morphysorb Process

>

What is it?–

Proprietary solvent/process(GTI and Uhde own the technology)

–

N- formyl morpholine/N-acetyl morpholine mixtures

>

What is the application?–

Bulk or trace removal of acid gas components –

Subquality natural gas upgrading to either pipeline or LNG specification

–

Selective removal of H2 S from natural/synthesis gas for generation of acid gas stream suitable for Claus plant feed

–

Selective removal of H2 S, CO2 , COS, CS2 , mercaptans and other components from coal/oil gasification syngas at IGCC facilities


Morphysorb Process>

Advantages–

Higher solvent loading = lower circulation or higher throughput

–

Lower co-absorption of hydrocarbons (less losses)-less recycle gas flow

–

Lower CO and H2 absorption

–

In situ, partial COS Hydrolysis

–

Low corrosion, low environmental hazard

–

Low capital and operating costs


Syngas Component Absorption

Component DMEPEG Morphysorb (100%

NFM)

CH4 7 25

CO 25 >220

H2 50 124

Ref: Zawacki et al., Hydrocarbon Processing, April 1981 “Process Optimized for high pressure gas cleanup

K values = y/x


>Kwoen Gas Plant Plant started in late 2002>Owned by Spectra EnergySM

Transmission>300 MMscfd (8.5 m3/d) orig., 450 MMscfd (12.75

m3/d) expansion>Bulk removal of 25+% acid gas concentration

stream>~4500 gpm (1000 m3/h) circulation>~2000 psia (13.8 MPa) liquefied acid gas to

injection Spectra Energy Kwoen Plant

ca.

2002

Absorber towers

Solvent storage

Flash drums

Natural Gas Commercial Application


Acid Gas Treating Pilot Plant

Orig. 15 gpm (15 L/m)unit

Upgraded 40 gpm (150 L/m)

unit at GTI, Des Plaines, IL

Can process full flow from GTI Flex Fuel Test Facility 10‐20 TPD gasifier

~ 1MMscfd (28,000 Nm3 /hr)


AGTPP

> Absorber ─

33.5 ft. (10.2 m) of packed height

─

14.7 inches (37 cm) internal diameter ─

Koch Type 350Y Flexipac elements

─

1200 psi (~80 bar) maximum operating pressure

> Regenerator ─

40.7 ft. (12.4 m) of packed height

─

12 inches internal diameter (30.5 cm) ─

Koch Type 350Y Flexipac elements

─

50 psig (4.5 bara) maximum operating pressure


Morphysorb Conclusions

>

Natural gas bulk removal application - proven very reliable and efficient

>

Syngas treating - May be viable and beneficial but pilot plant data are needed, at a minimum

>

Solvent swap may be possible, as done for natural gas

>

A competitor to existing physical solvent options would be of value to the budding gasification industry to keep prices competitive

>

GTI/Uhde will continue to advance Morphysorb for multiple applications throughout studies, pilot and demonstration applications


CarboLock Carbon Capture Device


Advantages of The Membrane Contactor Process

The gas/liquid contactor is a hybrid between membrane and the conventional absorption processes. Process features:Counter-current flow is thermodynamically most efficient mass transferStructured packing of hollow fibers critical for efficient, high specific surface area, mass transfer. Computer controlled winding enhances turbulence flow at fiber surfaceHigh temperature stability for desorption stepIncreased mass transfer reduces system sizeIndependent gas and liquid flowLinear scale upConcentrated solvents or specialty absorbents can be used


Membrane Material Properties of PEEK

Very high heat resistance, rigidity & strengthExcellent sliding friction behavior, minimal abrasionExcellent chemical resistanceExcellent hydrolytic stabilityAverage pore size can be tailored from 1 to 50 nmPore morphology can be symmetric or asymmetricAverage porosity can range from 50 to 70%800 psi (5.5 MPa) water breakthrough pressure

PEEK Hollow Fiber

PEEK can operate continuously in contact with aggressive amine solvents


Benefits of Integral Membrane/ Absorption Process

Membrane Advantages:•Capital Cost (CapEx) 35%•Operating Costs (OpEx) 40%•Dry Equipment Weight 35%•Operating Equipment Weight 37%•Total Operating Weight 47% •Footprint Requirement 40%•Height Requirement 60%

*Data by Aker Kvaerner

Conventional AmineScrubber Column

Membrane Contactor


Module Fabrication

Tubesheet material•

Specialty epoxies compatible with amines and other solvents

Well established potting process

Module area up to 1000 ft2 (100 m2) and module diameter from 2 to 12 inches (5 to 30 cm)

Structured packing attained by computer-controlled hollow fiber helical winding processLow pressure drop and high mass transfer rate obtained


Bench Test Unit

•

0.6 MMscfd (17,000 m3/d) N2

/CO2

mixture•

14 gallon/hr (53 L/h) solvent flow

•

1000 psig (6.9 MPa)•

25 to 75 ºC

•

Moisture addition and measurement

•

Fully instrumented and computer controlled.

This unit is located in GTI’s Gas Processing Lab 636.


CO2 Removal at High Pressures

Inlet P = 500 psig (3.4 MPa)Gas T = 25ºCLiquid T = 25ºCInlet CO2

= 38%V


Technology Status – Modeling

•

Applications for the simulation program (absorption):Low pressure CO2-removal (exhaust gas) – MEALow pressure CO2-removal (exhaust gas) – MDEA/PiperazineDehydration / H2O-removal (natural gas) – TEGSweetening / CO2 and H2S removal (natural gas) –MDEA/PiperazineSweetening / CO2 and H2S removal (natural gas) – Sulfinol-DSweetening / CO2 and H2S removal (natural gas) – Morphysorb

•

Applications for the simulation program (desorption):CO2 / MEACO2 / MDEA


Conclusions

>No “silver bullet”

process that can treat gas to IGCC or XtL

specs

>New integrated processes provide potential for energy and cost savings

>GTI is seeking opportunities to advance these technologies to help advance IGCC and XtL

projects

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