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 2

3 Topics Chemical Absorption Processes Physical Absorption Adsorption Cryogenic Fractionation Membranes Nonregenerable H 2 S Scavengers Biological Processes Safety and Environmental Considerations 3

4 Gas treating Gas treating involves removing the acid gases to sufficiently low levels to meet contractual specifications Carbon dioxide (CO 2 ) Hydrogen sulfide (H 2 S) Plus other sulfur species The problems 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 H2S: Pipeline quality gas requires 0.25 grains/100 scf (4 ppmv) CO2: 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 500m OIL CH 4 CO 2 CO 2 CO m 1500m IMPERMEABLE CAP-ROCK SALINE RESERVOIR 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 CO2 Sources & Disposition Options Study places CO2 capture cost between $34 and $61/ton Oil & Gas Journal, Oct. 12,

8 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,

9 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 9

10 Selecting a process 10 3 Hybrid Physical Solvent, Hybrid, or Hot Potassium Carbonate Physical Solvent Partial Pressure of Acid Gas in Feed, psia Amine Physical Solvent or Activated Hot Potassium Carbonate Activated Hot Potassium Carbonate Or Inhibited Concentrated Amine Activated Hot Potassium Carbonate or Amine Line of Equal Inlet and Outlet Pressures Partial Pressure of Acid Gas in Product, psia

11 Topics Chemical Absorption Processes Physical Absorption Adsorption Cryogenic Fractionation Membranes Nonregenerable H 2 S Scavengers Biological Processes Safety and Environmental Considerations 11

12 Physical absorption 12

13 Chemical absorption 13

14 Amine Chemistry Gas treating amines are: AMINE Primary amine (MEA) A = CH 2 CH 2 OH B = H C = H 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 14

15 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 15

16 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 R 1 R 2 R 3 N + H 2 S R 1 R 2 R 3 NH+HS - CO 2 reacts two ways with amine: 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 16

17 Comparison of acid gas removal solvents Process Monoethanolamine (MEA) Capable of meeting H2S spec? Removes COS, CS2, & mercaptans Selective H2S removal Minimum CO2 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, CO2, CS2, SO2, SO3 and mercaptans) Some (COS, CO2 CS2, HCN and mercaptans) Slight (COS, CS2 and mercaptans) No 17

18 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 0.55 ~0.12 ~0.08 ~ to

19 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 19

20 Heats of reaction in amine solutions Amine H 2 S, Btu/lb (kj/kg) CO 2, Btu/lb (kj/kg) DGA 674 (1570) 850 (1980) MEA 610 (1420) 825 (1920) DEA 555 (1290) 730 (1700) MDEA 530 (1230) 610 (1420) Includes heat of solution & heat of reaction Can give rise to temperature bulges in the absorbing column 20

21 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 21

22 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 o 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 22

23 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] 23

24 Simplified Design Calculations Estimate amine circulation rate Qy GPM = C x C = 41 if MEA 45 if DEA 32 if DEA (high loading) 55.8 if DGA Q = Sour gas to be processed [MMscfd] y = Acid gas concentration in inlet gas [mol%] x = Amine concentration in liquid solution [wt%] Use only if combined H 2 S + CO 2 in gas below 5 mol% Amine concentration limited to 30 wt% 24

25 Amine Approximate Guidelines MEA DEA DGA Acid gas pickup 100 F Acid gas pickup mol/mol amine Lean solution residual acid gas mol/mol amine Solution concentration wt% Reboiler duty BTU/gal lean solution 1,000-2, ,000 1,100-1,300 Steam heated reboiler tube bundle flux Btu/hr-ft² 9,000-10,000 6,300-7,400 9,000-10,000 Direct fired reboiler tube bundle flux Btu/hr-ft² 8,000-10,000 6,300-7,400 8,000-10,000 Reclaimer steam bundle or fire tube flux Btu/hr-ft² 6-9 N/A 6-8 Reboiler temperature F Heat of reaction Btu/lb H 2 S Btu/lb CO

26 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) 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 Topics Chemical Absorption Processes Physical Absorption Adsorption Cryogenic Fractionation Membranes Nonregenerable H 2 S Scavengers Biological Processes Safety and Environmental Considerations 28

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 Topics Chemical Absorption Processes Physical Absorption Adsorption Cryogenic Fractionation Membranes Nonregenerable H 2 S Scavengers Biological Processes Safety and Environmental Considerations 36

37 Membrane systems Based on Fick s law of diffusion through the membrane J i SD ( 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 CO2 removal High hydrocarbon recovery Requires recycle compressor Feed with high CO2 Intermediate hydrocarbon recovery Reduced compression UOP Separex TM Membrane Technology, UOP, 2009 Retrieved March 2016 from 41

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

43 Topics Chemical Absorption Processes Physical Absorption Adsorption Cryogenic Fractionation Membranes Nonregenerable H 2 S Scavengers Biological Processes Safety and Environmental Considerations 43

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

45 Topics Chemical Absorption Processes Physical Absorption Adsorption Cryogenic Fractionation Membranes Nonregenerable H 2 S Scavengers Biological Processes Safety and Environmental Considerations 45

46 Nonregenerable H2S 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,

47 Topics Chemical Absorption Processes Physical Absorption Adsorption Cryogenic Fractionation Membranes Nonregenerable H 2 S Scavengers Biological Processes Safety and Environmental Considerations 47