Acid Gas Treating. Chapter 10 Based on presentation by Prof. Art Kidnay

Transcription

1 Acid Gas Treating Chapter 10 Based on presentation by Prof. Art Kidnay

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

3 Topics Chemical Absorption Processes Physical Absorption Adsorption Cryogenic Fractionation Membranes Nonregenerable H2S Scavengers Biological Processes Safety and Environmental Considerations 3

4 Gas treating Gas treating involves removing contaminants to sufficiently low levels to meet specifications Primary focus on removing acid gases Carbon dioxide (CO 2 ) Hydrogen sulfide (H 2 S) Plus other sulfur species Other contaminants Mercury Ammonia Elemental sulfur Arsenic The acid gas problem H 2 S is highly toxic H 2 S combustion gives SO 2 toxic & leads to acid rain CO 2 is a diluent in natural gas corrosive in presence of H 2 O Purification levels H 2 S: Pipeline quality gas requires 0.25 grains/100 scf (4 ppmv) CO 2 : pipeline quality gas may allow up to 4 mole% Cryogenic applications need less than 50 ppmv 4

5 Two step process Two steps Remove the acid gases from natural gas Dispose of the acid gases Disposition CO 2 Vent to atmosphere EOR Enhanced Oil Recovery Sequestration H 2 S Incineration or venting (trace amounts) React with scavengers (e.g. iron sponge) Convert to elemental sulfur Injection into suitable underground formation 5

6 CO2 Capture and Sequestration Power Station/Industrial Facility 500 m OIL CH 4 CO 2 CO 2 CO m 1500m IMPERMEABLE CAP-ROCK SALINE RESERVOI R IMPERMEABLE CAP-ROCK CO 2 Replaces Methane Trapped in Coal Enhanced Oil Recovery (CO 2 Displaces Oil) IMPERMEABLE CAP-ROCK CO 2 Stored in Saline Formation COAL SEAM 6

7 Processes for acid gas removal Acid Gas Removal Processes Solvent Absorption Chemical Physical Hybrid Solid Adsorption Membranes Direct Conversion Cryogenic Fractionation Selexol Sulfinol Molecular sieve Cellulose acetate Stretford Ryan-Holmes Amine MEA DGA DEA DIPA Alkali Salts Benfield Catacarb Giammarco Vetrocoke Flexsorb HP Rectisol Ifpexol Purisol Sepasolv MPE Selefining Amisol Iron sponge Zinc oxide Polyimide Polysulfone Lo Cat MDEA Amine mixtures Hindered amines Figure 10.1, Fundamentals of Natural Gas Processing, 2 nd ed., Kidnay, Parrish, & McCartney,

8 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 CO 2 Only H 2 S Both CO 2 and H 2 S Both CO 2 and H 2 S present but selectively remove H 2 S Allow CO 2 slip 8

9 Selecting a process Figure 10.2, Fundamentals of Natural Gas Processing, 2 nd ed., Kidnay, Parrish, & McCartney,

10 Chemical Absorption Processes Copyright 2017 John Jechura

11 Physical vs. Chemical Absorption 11

12 Amine Chemistry AMINE Primary amine (MEA) A = CH 2 CH 2 OH B = H C = H Gas treating amines are: Weak Lewis Bases H + from weak acids react with the electrons on N: A N B C Secondary amine (DEA) A = CH 2 CH 2 OH B = CH 2 CH 2 OH C = H Tertiary amine (MDEA) A = CH 2 CH 2 OH B = CH 2 CH 2 OH C = CH 3 ABC substituents influence: How fast acids react with N: Temperature bulge in absorber Energy required in regenerator Chemical Stability Unwanted reactions Dow Oil & Gas Gas Treating Technology Presentation to URS Washington Division, August 2009 Rich Ackman ackmanrb@dow.com 12

13 Sterically hindered amines selective H 2 S absorbers Diisopropanolamine (DIPA) 2-amino,2-methyl,1-propanol (AMP) CH 3 HOCH 2 C NH 2 CH 3 13

14 Amines Amines remove H 2 S and CO 2 in two step process: Gas dissolves in solvent (physical absorption) Dissolved gas (a weak acid) reacts with weakly basic amines H 2 S reaction CO 2 reacts two ways with amine: R 1 R 2 R 3 N + H 2 S R 1 R 2 R 3 NH+HS - With water CO 2 + H 2 O + R 1 R 2 R 3 N R 1 R 2 R 3 NH + HCO - 3 Much slower than H 2 S reaction Without water CO R 1 R 2 NH R 1 R 2 NH 2 + R 1 R 2 NCOO - Faster but requires one H attached to the N Use tertiary amines to slip CO 2 14

15 Comparison of acid gas removal solvents Process Monoethanolamine (MEA) Capable of meeting H 2 S spec? Removes COS, CS 2, & mercaptans Selective H 2 S removal Minimum CO 2 level obtainable Yes Partial No 100 ppmv at low to moderate pressures Diethanolamine (DEA) Yes Partial No 50 ppmv in SNEA-DEA process Triethanolamine (TEA) No Slight No Minimum partial pressure of 0.5 psia (3 kpa) Methyldiethanolamine (MDEA) Yes Slight Some Bulk removal only Solution subject to degradation? (degrading species) Yes (COS, CO 2, CS 2, SO 2, SO 3 and mercaptans) Some (COS, CO 2, CS 2, HCN and mercaptans) Slight (COS, CS 2 and mercaptans) No Part of Table 10.1, Fundamentals of Natural Gas Processing, 2 nd ed., Kidnay, Parrish, & McCartney,

16 Representative operating parameters MEA DEA DGA MDEA Weight % amine 15 to to to to 50 Rich amine acid gas loading mole acid gas / mole amine Acid gas pickup mole acid gas / mole amine Lean solution residual acid gas mole acid gas / mole amine 0.45 to to to to to to to to 0.80 ~0.12 ~0.01 ~ to 0.01 Table 10.3, Fundamentals of Natural Gas Processing, 2 nd ed., Kidnay, Parrish, & McCartney,

17 Gas Treating Amines Generic Amines MEA (monoethanolamine) 15 18% wt. (5 6.1% mol) DEA (diethanolamine) 25 30% wt. ( % mol) DIPA (diisopropanolamine) 30% - 50% wt. ( % mol) MDEA (methyldiethanolamine) 35% - 50% wt. ( % mol) Wt% Mol% Load Relative Range Capacity MEA 18% 6.1% DGA 50% 14.6% DEA 28% 6.3% MDEA 50% 13.1% CompSol 20 50% 10.4% CR % 14.7% AP % 13.9% Dow Oil & Gas Gas Treating Technology Presentation to URS Washington Division, August 2009 Rich Ackman ackmanrb@dow.com 17

18 Amine Solution Densities Lean amine composition will dictate volumetric circulation rate & pumping power required Need to determine density/volumetric flow at actual pumping temperature W BHP ( ) ( ) m P V P V gh = = = pump pump pump GPSA Engineering Data Book, 13 th ed. 18

19 Amine Solution Densities Figures B.1 & B.2, Fundamentals of Natural Gas Processing, 2 nd ed., Kidnay, Parrish, & McCartney,

20 Typical Amine Treating Plant Typical plant configuration Broad range of treating applications Low to intermediate specifications Selective treating, low H 2 S Low installed cost 20

21 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 Capacity vs. efficiency, GPDC overlay Structured Packing Dow Oil & Gas Gas Treating Technology Presentation to URS Washington Division, August 2009 Rich Ackman ackmanrb@dow.com 21

22 Amine Tower Parameters Absorber design considerations Pinch points limit Top of tower lean pinch Temperature bulge maximum Bottom of tower rich pinch Confidence level in VLE Temperature profile indicator Stage Absorber Temperature Profiles Liquid Phase C-1 Conservative C-2 Controlled Efficient C-3 Intercooler Temperature [ F] 22

23 Amine Approximate Guidelines MEA DEA DGA MDEA Acid gas pickup, 100 F Acid gas pickup, mols/mol amine Lean solution residual acid gas, mol/mol amine ~ 0.12 ~ 0.01 ~ Rich solution acid gas loading, mol/mol amine Max. solution concentration, wt% Approximate reboiler heat duty, Btu/gal lean solution Steam heated ave. heat flux in reboiler, Btu/hr ft 2 9,000 10,000 1,000 1, ,000 6,300 7,400 1,100 1, ,000 10,000 6,300 7,400 Reboiler temperature, F Heats of reaction (approximate) Btu/lb H 2 S 610 Btu/lb CO GPSA Engineering Data Book, 14 th ed., portion of Figure

24 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 (CO 2 & H 2 S) 24

25 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) 25

26 HYSYS Example Simulation 26

27 Hot potassium carbonate process (Hot Pot) Major reactions K 2 CO 3 + CO 2 + H 2 O 2 KHCO 3 Acid Gas K 2 CO 3 + H 2 S KHS + KHCO 3 Sweet Product Gas Condenser Lean Solution Sour Feed Gas contactor Steam Absorber Rich Solution Stripper 27

28 Physical Absorption Copyright 2017 John Jechura

29 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 Can be carried out at nearambient temperatures Partial dehydration occurs along with acid gas removal Figure from UOP Selexol TM Technology for Acid Gas Removal, UOP, 2009 Retrieved March 2016 from 29

30 Comparison of chemical and physical solvents Chemical Solvent (e.g., amines, hot potassium carbonate) Physical solvents (e.g., Selexol, Rectisol) Advantages Relatively insensitive to H 2 S and CO 2 partial pressure Can reduce H 2 S and CO 2 to ppm levels Low energy requirements for regeneration Can be selective between H 2 S and CO 2 Disadvantages High energy requirements for regeneration of solvent Generally not selective between CO 2 and H 2 S Amines are in a water solution and thus the treated gas leaves saturated with water May be difficult to meet H 2 S specifications Very sensitive to acid gas partial pressure 30

31 Physical Solvents Selexol Characteristics Poly (Ethylene Glycol) Dimethyl Ether CH 3 - O - (CH 2 - CH 2 - O) n - CH 3 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 H 2 S selective or non selective removal very low spec. - 4 ppm CO 2 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 31

32 Selexol Processes Physical solvent which favors high pressure & high partial pressure Configurations H 2 S & organic sulfur removal Steam stripping for regeneration CO 2 removal Flash regeneration Chiller for low CO 2 Special applications Siloxanes are removed from landfill gas Metal carbonyl are removed from gasifier gas 32

33 Solubility in Selexol at 70 o F (21 o C) 30 H 2 S Solubility, scf / gal Selexol CH 3 SH CO 2 COS CH Gas Partial Pressure, psia Figure 10.6, Fundamentals of Natural Gas Processing, 2 nd ed., Kidnay, Parrish, & McCartney,

34 Selexol process CO 2 separation UOP Selexol TM Technology for Acid Gas Removal, UOP, 2009 Retrieved March 2016 from 34

35 Selexol process sulfur removal & CO 2 capture UOP Selexol TM Technology for Acid Gas Removal, UOP, 2009 Retrieved March 2016 from 35

36 Membranes Copyright 2017 John Jechura

37 Membrane systems Based on Fick s law of diffusion through the membrane J i S D ( p ) = i i i L where: J i is the molar flux of component i through the membrane S i is the solubility term D i is the diffusion coefficient Δp i is the partial pressure difference across the membrane L is the thickness of the membrane The permeability combines the properties of solubility & diffusion Differs for each compound Provides selectivity y i,permeate P P feed permeate y i,feed 37

38 Module configurations hollow fiber Approximately 70% of membrane systems are hollow fiber Low Pressure, Bore-Side Gas Feed Module Courtesy MTR 38

39 Module configurations spiral wound Continued Development of Gas Separation Membranes for Highly Sour Service, Cnop, Dormndt, & schott, UOP Retrieved March 2016 from 39

40 Module configurations spiral wound 40

41 Membrane module flow schemes No moving parts Simple, reliable operation Low hydrocarbon recovery Allows for greater CO 2 removal High hydrocarbon recovery Requires recycle compressor Feed with high CO 2 Intermediate hydrocarbon recovery Reduced compression UOP Separex TM Membrane Technology, UOP, 2009 Retrieved March 2016 from 41

42 CO 2 /CH 4 Separation Example Two stage process (non-optimized) 42

43 CO 2 /CH 4 Separation Example Retentate (B) Retentate (B) Feed (A) Permeate (C) Feed (A) (D) Permeate (C) (E) 43

44 Adsorption Copyright 2017 John Jechura

45 Acid gas removal by adsorption (mole sieves) Figure 10.10, Fundamentals of Natural Gas Processing, 2 nd ed., Kidnay, Parrish, & McCartney,

46 Nonregenerable H 2 S Scavengers Copyright 2017 John Jechura (jjechura@mines.edu)

47 Nonregenerable H 2 S scavengers Process Phase Solid-based processes Liquid-based processes Process Iron oxides Zinc oxides Amine-aldehyde condensates Caustic Aldehydes Oxidizers Metal-oxide slurries Table 10.9, Fundamentals of Natural Gas Processing, 2 nd ed., Kidnay, Parrish, & McCartney,

48 Summary Copyright 2017 John Jechura

49 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 H 2 S and/or CO 2 May be able to slip CO2 into treated gas depending on the final specs 49

50 Supplemental Slides Copyright 2017 John Jechura

51 CO 2 Sources & Disposition Options Study places CO2 capture cost between $34 and $61/ton Oil & Gas Journal, Oct. 12,