Acid Gas Treating

Chapter 10 Based on presentation by Prof. Art Kidnay Plant Block Schematic

Adapted from Figure 7.1, Fundamentals of Natural Gas Processing, 2nd ed. Kidnay, Parrish, & McCartney

Updated: January 4, 2019 2 Copyright © 2019 John Jechura ([email protected]) Topics Chemical Absorption Processes Physical Absorption Adsorption Cryogenic Fractionation Membranes Nonregenerable H2S Scavengers Biological Processes Safety and Environmental Considerations

Updated: January 4, 2019 3 Copyright © 2019 John Jechura ([email protected]) Gas treating Gas treating involves removing The acid gas problem contaminants to sufficiently ▪ H2S is highly toxic low levels to meet ▪ H2S combustion gives SO2 – toxic specifications & leads to acid rain ▪ Primary focus on removing “acid ▪ CO2 is a diluent in natural gas – gases” corrosive in presence of H2O

• Carbon dioxide (CO2) Purification levels • Hydrogen sulfide (H S) 2 ▪ H2S: Pipeline quality gas requires • Plus other sulfur species 0.25 grains/100 scf (4 ppmv)

▪ Other contaminants ▪ CO2: pipeline quality gas may • Mercury allow up to 4 mole% • Ammonia • Cryogenic applications need • Elemental sulfur less than 50 ppmv • Arsenic Updated: January 4, 2019 4 Copyright © 2019 John Jechura ([email protected]) Two step process Two steps ▪ Remove the acid gases from natural gas ▪ Dispose of the acid gases Disposition

▪ CO2 • Vent to atmosphere • EOR – Enhanced Oil Recovery • Sequestration

▪ H2S • Incineration or venting (trace amounts) • React with scavengers (e.g. iron sponge) • Convert to elemental sulfur • Injection into suitable underground formation

Power Station/Industrial Facility

500 m CO CO OIL CO 2 CH 2 4 2 1000m IMPERMEABLE CAP-ROCK COAL CO2 Replaces Methane SEAM IMPERMEABLE Trapped in Coal 1500m CAP-ROCK Enhanced Oil Recovery SALINE (CO2 Displaces Oil) RESERVOI CO2 Stored in Saline RIMPERMEABLE Formation CAP-ROCK

Acid Gas Removal Processes

Solvent Absorption

Solid Direct Cryogenic Physical Hybrid Membranes Chemical Adsorption Conversion Fractionation Molecular Cellulose Selexol Sulfinol sieve acetate Stretford Ryan-Holmes Amine Alkali Salts Rectisol Selefining Iron sponge Polyimide Lo Cat MEA Benfield Ifpexol Amisol Zinc oxide Polysulfone DGA Catacarb Purisol Giammarco DEA Vetrocoke Sepasolv MPE DIPA Flexsorb HP

MDEA Amine mixtures Hindered amines

Figure 10.1, Fundamentals of Natural Gas Processing, 2nd ed., Kidnay, Parrish, & McCartney, 2011

Updated: January 4, 2019 7 Copyright © 2019 John Jechura ([email protected]) Selecting a process Factors for selecting process ▪ Type & concentration of impurities ▪ Hydrocarbon composition of the gas ▪ Pressure & temperature of the gas ▪ Specifications for outlet gas ▪ Volume of gas to be processed Four possible scenarios

▪ Only CO2

▪ Only H2S

▪ Both CO2 and H2S

▪ Both CO2 and H2S present but selectively remove H2S

• Allow CO2 slip

Figure 10.2, Fundamentals of Natural Gas Processing, 2nd ed., Kidnay, Parrish, & McCartney, 2011

Primary amine (MEA) Gas treating amines are: A = CH2CH2OH ▪ Weak Lewis Bases B = H ▪ H+ from weak acids react

AMINE C = H with the electrons on N:

l l N Secondary amine (DEA) A = CH2CH2OH ABC substituents influence: B = CH2CH2OH ▪ How fast acids react with N: C = H ▪ Temperature bulge in A C absorber ▪ B Tertiary amine (MDEA) Energy required in A = CH CH OH regenerator 2 2 ▪ Chemical Stability B = CH2CH2OH C = CH3 ▪ Unwanted reactions

Dow Oil & Gas – Gas Treating Technology Presentation to URS Washington Division, August 2009 Rich Ackman – [email protected]

Diisopropanolamine (DIPA) 2-amino,2-methyl,1-propanol (AMP)

CH3

HOCH2 C NH2

CH3

Amines remove H2S and CO2 in two step process: ▪ Gas dissolves in solvent (physical absorption) ▪ Dissolved gas (a weak acid) reacts with weakly basic amines

H2S reaction - R1R2R3N + H2S ↔ R1R2R3NH+HS

CO2 reacts two ways with amine: ▪ With water + - CO2 + H2O + R1R2R3N ↔ R1R2R3NH HCO3

• Much slower than H2S reaction ▪ Without water - CO2 + 2 R1R2NH ↔ R1R2NH2 + R1R2NCOO • Faster but requires one H attached to the N

• Use tertiary amines to “slip” CO2

Process Capable of Removes Selective Minimum CO2 Solution subject meeting COS, CS2, & H2S level to degradation? H2S spec? mercaptans removal obtainable (degrading species)

Monoethanolamine Yes Partial No 100 ppmv at Yes (COS, CO2, (MEA) low to CS2, SO2, SO3 and moderate mercaptans) pressures

Diethanolamine (DEA) Yes Partial No 50 ppmv in Some (COS, CO2, SNEA-DEA CS2, HCN and process mercaptans)

Triethanolamine (TEA) No Slight No Minimum Slight (COS, CS2 partial and mercaptans) pressure of 0.5 psia (3 kPa) Methyldiethanolamine Yes Slight Some Bulk removal No (MDEA) only

Part of Table 10.1, Fundamentals of Natural Gas Processing, 2nd ed., Kidnay, Parrish, & McCartney, 2011

MEA DEA DGA MDEA Weight % amine 15 to 25 30 to 40 50 to 60 40 to 50 Rich amine acid gas loading 0.45 to 0.52 0.21 to 0.81 0.35 to 0.44 0.20 to 0.81 mole acid gas / mole amine Acid gas pickup 0.33 to 0.40 0.20 to 0.80 0.25 to 0.38 0.20 to 0.80 mole acid gas / mole amine Lean solution residual acid gas ~0.12 ~0.01 ~0.06 0.005 to 0.01 mole acid gas / mole amine

Table 10.3, Fundamentals of Natural Gas Processing, 2nd ed., Kidnay, Parrish, & McCartney, 2011

Updated: January 4, 2019 16 Copyright © 2019 John Jechura ([email protected]) Gas Treating Amines Generic Amines Load Relative ▪ MEA Wt% Mol% Range Capacity (monoethanolamine) MEA 18% 6.1% 0.35 1 • 15 – 18% wt. (5 – 6.1% mol) DGA 50% 14.6% 0.45 3.09 ▪ DEA (diethanolamine) DEA 28% 6.3% 0.48 1.41 MDEA 50% 13.1% 0.49 3.02 • 25 – 30% wt. (5.4 – 6.8% CompSol 20 50% 10.4% 0.485 2.37 mol) CR 402 50% 14.7% 0.49 3.38 ▪ DIPA AP 814 50% 13.9% 0.485 3.16 (diisopropanolamine) • 30% - 50% wt. (5.5 – 11.9% Dow Oil & Gas – Gas Treating Technology Presentation to URS Washington Division, August 2009 mol) Rich Ackman – [email protected] ▪ MDEA (methyldiethanolamine) • 35% - 50% wt. (7.5 – 13.1% mol)

Updated: January 4, 2019 17 Copyright © 2019 John Jechura ([email protected]) Amine Solution Densities Lean amine composition will dictate volumetric circulation rate & pumping power required ▪ Need to determine density/volumetric flow at actual pumping temperature

m( P) V( P) V gH WBHP = = = pump  pump  pump

GPSA Engineering Data Book, 13th ed.

Figures B.1 & B.2, Fundamentals of Natural Gas Processing, 2nd ed., Kidnay, Parrish, & McCartney, 2011

Typical plant configuration ▪ Broad range of treating applications ▪ Low to intermediate specifications

▪ Selective treating, low H2S ▪ Low installed cost

Updated: January 4, 2019 20 Copyright © 2019 John Jechura ([email protected]) Amine Tower Parameters Tower Design Considerations ▪ Gas Composition ▪ Trays • System Factor Bubble Area o MEA/DEA – 0.75 abs (0.85 reg) o MDEA & Formulated Solvents – 0.70 abs (0.85 reg) • System Factor Downcomer o MEA/DEA – 0.73 abs (0.85 reg) o MDEA & Formulated Solvents – 0.70 abs (0.85 reg) o Standard Cross Flow vs. High Capacity ❖ Calming Section, MD Trays ▪ Packings • Random Packing Dow Oil & Gas – Gas Treating Technology • Capacity vs. efficiency, GPDC overlay Presentation to URS Washington Division, August 2009 • Structured Packing Rich Ackman – [email protected]

Absorber Temperature Profiles Absorber design considerations Liquid Phase

1 ▪ Pinch points limit 2 3 C-1 Conservative 4 • Top of tower lean pinch C-2 Controlled Efficient 5 C-3 Intercooler 6 • Temperature bulge maximum 7 8 • Bottom of tower rich pinch 9 10 • Confidence level in VLE 11 12 13 ▪ Stage Temperature profile indicator 14 15 16 17 18 19 20 21 22 23 24 80 100 120 140 160 180 200

Temperature [°F]

MEA DEA DGA MDEA

Acid gas pickup, scf/gal @ 100°F 3.1 – 4.3 6.7 – 7.5 4.7 – 7.3 3 – 7.5

Acid gas pickup, mols/mol amine 0.33 – 0.40 0.20 – 0.80 0.25 – 0.38 0.20 – 0.80

Lean solution residual acid gas, mol/mol amine ~ 0.12 ~ 0.01 ~ 0.06 0.005 – 0.01

Rich solution acid gas loading, mol/mol amine 0.45 – 0.52 0.21 – 0.81 0.35 – 0.44 0.20 – 0.81

Max. solution concentration, wt% 25 40 60 65

Approximate reboiler heat duty, Btu/gal lean 1,000 – 1,200 840 – 1,100 – 1,300 800 – 900 solution 1,000 Steam heated ave. heat flux in reboiler, Btu/hr ft2 9,000 – 6,300 – 9,000 –10,000 6,300 – 10,000 7,400 7,400 Reboiler temperature, °F 225 – 260 230 – 260 250 – 270 230 – 270

Heats of reaction (approximate)

Btu/lb H2S 610 555 674 530 Btu/lb CO2 825 730 850 610

GPSA Engineering Data Book, 14th ed., portion of Figure 21-4

Updated: January 4, 2019 23 Copyright © 2019 John Jechura ([email protected]) Amine System Initial Design Amine solvent considerations ▪ Lean amine concentration (wt% amine in water) ▪ Rich & lean amine loadings (mole acid gas per mole amine) – difference is the allowed amine pick-up Determine amount of acid gas to be absorbed ▪ Difference between what can be contained in the treated gas & what is in the feed gas Determine rate of lean amine to the absorber ▪ Molar rate amine based on the allowed pick-up ▪ Total mass rate amine+water based on the allowed lean amine concentration ▪ Total volumetric flowrate (standard conditions) based on lean amine concentration Determine the reboiler duty for regeneration

▪ Based on heat of regeneration for each amine & acid gas (CO2 & H2S)

Updated: January 4, 2019 24 Copyright © 2019 John Jechura ([email protected]) Operating issues with amine units Corrosion – caused by: ▪ High amine concentrations ▪ Rich amine loadings ▪ Oxygen ▪ Heat stable salts (HSS) Foaming – caused by ▪ Suspended solids ▪ Surface active agents ▪ Liquid hydrocarbons ▪ Amine degradation products (heat stable salts)

Updated: January 4, 2019 26 Copyright © 2019 John Jechura ([email protected]) Hot potassium carbonate process (Hot Pot) Major reactions Acid Gas K2CO3 + CO2 + H2O ⇄ 2 KHCO3 K CO + H S ⇄ KHS + KHCO 2 3 2 3 Sweet Condenser Product Gas

Lean Solution r o t c a t n o c Sour Feed Gas Steam

Rich Solution Absorber Stripper

Updated: January 4, 2019 Copyright © 2017 John Jechura ([email protected]) Characteristics of physical absorption processes Most efficient at high partial pressures Heavy hydrocarbons strongly absorbed by solvents used Solvents can be chosen for selective removal of sulfur compounds Regeneration requirements low compared to amines & Hot Pot Figure from UOP SelexolTM Technology for Acid Gas Removal, UOP, 2009 Retrieved March 2016 from http://www.uop.com/?document=uop-selexol-technology-for-acid-gas- Can be carried out at near- removal&download=1 ambient temperatures Partial dehydration occurs along with acid gas removal

Advantages Disadvantages

Chemical Solvent Relatively insensitive to H2S High energy requirements for (e.g., amines, hot and CO2 partial pressure regeneration of solvent potassium carbonate) Can reduce H2S and CO2 to Generally not selective ppm levels between CO2 and H2S Amines are in a water solution and thus the treated gas leaves saturated with water

Physical solvents Low energy requirements for May be difficult to meet H2S (e.g., Selexol, regeneration specifications Rectisol) Can be selective between H2S Very sensitive to acid gas and CO2 partial pressure

CH3 - O - (CH2 - CH2 - O)n - CH3 where n is from 3 to 10 ▪ Selexol is a mixture of homologues so the physical properties are approximate ▪ Clear fluid that looks like tinted water Capabilities

▪ H2S selective or non selective removal – very low spec. - 4 ppm

▪ CO2 selective or non selective removal – 2% to 0.1% ▪ Water dew point control ▪ Hydrocarbon dew point control • See relative solubilities; more efficient to remove hydrocarbon vs. refrigeration ▪ Organic sulfur removal – mercaptans, disulfides, COS

▪ H2S & organic sulfur removal • Steam stripping for regeneration

▪ CO2 removal • Flash regeneration

• Chiller for low CO2 Special applications ▪ Siloxanes are removed from landfill gas ▪ Metal carbonyl are removed from gasifier gas

H2S

30 l o x e l e S

a 20 g

f c s

, CH3SH y t

i CO l 2 i b u l o

S 10 COS

CH4

0 200 400 600 Gas Partial Pressure, psia

Figure 10.6, Fundamentals of Natural Gas Processing, 2nd ed., Kidnay, Parrish, & McCartney, 2011

UOP SelexolTM Technology for Acid Gas Removal, UOP, 2009 Retrieved March 2016 from http://www.uop.com/?document=uop-selexol-technology-for-acid-gas-removal&download=1

S D( p ) J = i i i i L where: Ji is the molar flux of component i through the membrane

Si is the solubility term Di is the diffusion coefficient Δpi is the partial pressure difference across the membrane L is the thickness of the membrane The permeability combines the properties of P yy feed solubility & diffusion ii,permeate ,feed Ppermeate ▪ Differs for each compound ▪ Provides selectivity

Low Pressure, Bore-Side Gas Feed Module

Courtesy MTR

Continued Development of Gas Separation Membranes for Highly Sour Service, Cnop, Dormndt, & schott, UOP Retrieved March 2016 from http://www.uop.com/?document=uop-continued-development-of-gas-separation-membranes-technical- paper&download=1

No moving parts Allows for greater CO removal Simple, reliable operation 2 High hydrocarbon recovery Low hydrocarbon recovery Requires recycle compressor

Feed with high CO2 Intermediate hydrocarbon recovery

UOP SeparexTM Membrane Technology, UOP, 2009 Reduced compression Retrieved March 2016 from http://www.slideshare.net/hungtv511/uop-separex-membrane-technology

Retentate (B) Feed (A) Permeate (C)

Feed (A)

(D)

Permeate (C)

(E)

Figure 10.10, Fundamentals of Natural Gas Processing, 2nd ed., Kidnay, Parrish, & McCartney, 2011

Process Phase Process Solid-based processes Iron oxides Zinc oxides Liquid-based processes Amine-aldehyde condensates Caustic Aldehydes Oxidizers Metal-oxide slurries

Table 10.9, Fundamentals of Natural Gas Processing, 2nd ed., Kidnay, Parrish, & McCartney, 2011

Updated: January 4, 2019 Copyright © 2017 John Jechura ([email protected]) Summary Appropriate technology based on… ▪ Amount of acid gas to be removed ▪ Concentration of acid gas in feed gas ▪ Pressure of feed gas

Very typical to find an amine treating system to remove H2S and/or CO2 ▪ May be able to “slip” CO2 into treated gas depending on the final specs

“Study places CO2 capture cost between $34 and $61/ton” Oil & Gas Journal, Oct. 12, 2009