1. Natural Gas Processing I Chapter 4 Gas and Product Treating
PTRT 1317
Natural Gas Processing I
Chapter 4
Gas and Product Treating

2. Gas Treating
Removal of impurities from natural gas in the field or in a plant
We’ll focus this discussion on removal of acid and sour gases
Sulfur compounds
CO2
Typical US Sales Specs
H2S < 0.25 grains/100 scf (about 4 ppmv)
Total Sulfur < 5 grains/100 scf (80 ppmv)
CO2 < 2 mole%

3. Acid Gas Removal Chemical reaction using liquids or solids
Physical ABSORPTION in liquids
ADSORPTION on solids
Diffusion through membranes
Processes can be:
Regenerative (chemical is reprocessed and reused)
Non-regenerative
Trace amount of the contaminant (too expensive above 1 ton/day)
High purity is required

4. Chemical Reaction
Acid gases are chemically bound to the active ingredient in the treating solution
Chemical processes use weak bases
Alkanolamines
Alkali salt solutions
Potassium carbonate
Chelate solution (disodium EDTA)
Weak base reacts with the acid gases to produce a soluble salt

5. Amine-Based Solvents
Reaction usually takes place in a contactor (tower)
Solution is regenerated by reversing the reaction by raising the temperature and reducing the pressure
Amine process – diethanolamine (DEA) or methyldiethanolamine (MDEA) most common but the process description applies to most of the liquid absorption processes
In most applications the goal is:
Reduce H2S to 4 ppmv
CO2 to sales spec (usually 2 – 3%)
MDEA does not co-absorb much of the heavier hydrocarbons

7. Amine-Based Solvents
Monoethanolamine (MEA) – less used in recent years
High regeneration temps
MEA high corrosivity can be addressed
Limit concentration to 15-20%
Limit acid gas loading to 0.3 – 0.4 mole per mole of amine
Corrosion inhibitors (AmineGuard, GAS/SPEC)
Forms non-regenerable and highly corrosive degradation compounds with:
cobalt(II) carbonyl sulfide (COS)
Carbon disulfide (CS2)
Use of reclaimer reduces impact
High regeneration temp causes higher vaporization losses

8. Amine Reclaimer Amine reclaimer can greatly reduce operating problems
A portion of the lean amine is diverted to the reclaimer so that it can be distilled to remove:
degradation products
Heat stable salts
solids
Second reboiler uses sodium carbonate to recover amine from heat-stable salts (about 0.3% sodium carbonate is used)
However reclaimer is often omitted from amine systems

10. Amine-Based Solvents
Diethanolamine (DEA) – used for both gas and liquid hydrocarbon treating
Lower regeneration temp and corrosivity
DEA advantages over MEA
Can remove more acid gases
0.35 – 0.65 mole per mole of amine (compare to 0.3 – 0.4 with MEA)
Forms regenerable products with COS and CS2 eliminating the need for a reclaimer
Can be used for partial removal of COS and CS2
Disadvantages
limited ability to slip (reject) CO2 (Allow CO2 to pass through the absorber without being absorbed into the treating solution)
Higher operating pressure requirements

11. Amine-Based Solvents
Diglycolamine® (DGA®) - used in both natural gas and refinery gas treating
Removes H2S and CO2
Also removes 20-50% COS and Mercaptans
No significant ability to slip CO2
Higher affinity for aromatics and heavier hydrocarbons
Requires a reclaimer to remove degradation products
Low freezing point ( -30⁰F for 50% solution) favors use in colder climates

12. Amine-Based Solvents Methyldiethanolamine (MDEA)
Larger share of current gas treating market
Lower regeneration heat requirements
Low vapor pressure reduce vaporization losses
High selectivity for H2S over CO2
Slower reaction with CO2 means limiting contact time favors H2S removal
Higher concentration of H2S in the acid gas
Also useful for bulk removal of CO2 if sufficient contact time is provided

13. Approximate Guidelines for Commercial Gas Processes

15. Physical Properties

16. XTO Teague Treating Plant P&ID Review Photo Tour

17. Non Amine-based Processes
Hot KCO3 Process
Aqueous solution of potassium carbonate
Contactor operates between ⁰F
Not suitable to reduce down to pipeline specs
Redox Process
Oxidation/reduction process H2S reduced to elemental sulfur by reacting with oxygen
Slow process enhanced by auxiliary redox agents
Aqueous solution of iron-containing chelating agents

18. Biochemical Processes
Biological Oxidation Process
H2S converted directly to elemental sulfur
H2S reacts in the contactor with caustic solution (containing bacteria) to form sulfides
Solution flows to a reactor vessel where the bacteria (thiobacillus) converts sulfides to sulfur (eat the sulfides and excrete the sulfur)
Elemental sulfur is filtered from a side stream of the solution
Shell-Paques™ process is economical fro up to 30 tons per day of sulfur removal
Process used to treat:
Natural gas
Amine regenerator off gases
Claus tail gas residue
Refinery fuel gases
Waste gases

19. Shell-Paques™ Process

20. XTO Shell-Paques™ Plant
Review XTO Shell-Paques™ Plant Slides

21. Physical Absorption Processes
Solvent does not chemically react with the acid gas components
Physical solvent preferentially absorbs acid gases
Typically operate at ambient (or less) temperatures and high pressures
Physical solvent preferred when:
Acid gas partial pressure >50 psi
Heavy hydrocarbon in feed gas is low
Only bulk removal of acid gases is desired
Selective removal of H2S over CO2 is desired
If the conditions are met these solvents can be economical because very little energy is required for regeneration
Multistage flashing to progressively lower pressures
Low temperature with inert stripping gas
Steam stripping (same as amine still)

22. Typical Physical Solvent Plant

23. Physical Absorbants Selexol® Propylene Carbonate (Fluor Solvent™)
Higher solubility for H2S than CO2
Can remove COS, CS2 and mercaptans without degrading the solvent
Disadvantages
Co-absorption of heavy hydrocarbons
Solvent is expensive
Royalty charges
Propylene Carbonate (Fluor Solvent™)
Non-toxic, non-foaming and biodegradable
No heat required for regeneration
Low affinity for hydrocarbons
Higher solvent losses (higher vapor pressure)
Thermally unstable solvent
Higher operating costs

24. Physical Absorbants Rectisol® Process Sulfinol® Process
Methanol used as physical absorbant
Used on synthesis gas (hydrogen and CO) a byproduct of gasification of coal or heavy hydrocarbons
Operates at low temperature (-100 ⁰F to -30 ⁰F)
Sulfinol® Process
High acid gas loadings yield reduced circulation rates
Effective on many sulfur compounds
Selective for H2S when using MDEA
Low corrosivity and foaming tendencies
Disadvantages
High affinity for heavy hydrocarbons
DIPA degrades in the presence of CO2

25. Adsorption on a Solid – Molecular Sieve
Limited to low acid gas content (<15 ppmv of H2S)
Limited to low gas volumes (< 10 MMscf/day)
Cycle time 6-8 hours with 1 hour regeneration at ⁰F
Regeneration yield a peak H2S concentration in the regeneration gas about 30 times the concentration of H2S in the inlet gas stream
Operation is simple but the design is complex
Activated carbon similar but can accept higher acid gas content (<30 ppmv of H2S)

26. Membrane Processes
Different gas components diffuse (gas permeation) through membranes at different rates H2S and CO2 faster than hydrocarbons
Membrane is a thin polymeric film wound on a mandrel interleaved with spacer films
Acid gases enter the membrane and diffuse from the high pressure side of the membrane to the low pressure side and then out as permeate
Spiral-wound or hollow-fiber elements are housed in pressure tubes with up to six elements per tube.
Membrane systems are modular, skid-mounted units arranged in either series or parallel depending on requirements
Used to remove CO2
From 5 to 500 MMscf/d
Pressures between 400 – 1250 psig
CO2 levels between 3 and 60%

27. Membrane Processes Advantages Disadvantages
Lower capital and operating costs
Can treat and dehydrate to pipeline specs
Smaller footprint than amine system
Can be located
Offshore
Remote areas
Disadvantages
Economical only for bulk removal of CO2
Significant hydrocarbon loss to permeate stream (2-3% of inlet)
Membranes easily to damage from hydrocarbon liquid and particulates

29. Operating Amine Plants
Problems center around 5 major areas
Residue-gas specification
Corrosion
Foaming
Amine consumption
Winterization
Focus on MEA systems although similar approaches are used on other systems
(MDEA in paranthesis where known)

30. Residue Specification
Residue gas is TOO sour it MUST be contacted with more lean amine
Improve amine regeneration with added heat to increase steam stripping rate
If additional heat is not available then reduce amine circulation rate through the stripper
Amine decomposition products give off ammonia odor

31. MEA circulation rate AND concentrations should be kept within the marked triangle
Do not exceed 20% MEA (50% MDEA)
Do not exceed 0.4 mols (0.8 mols) acid gas per mol MEA (MDEA)
MEA has MW=61.08(MDEA has MW=119.16)
(Note: The numbers for MDEA obtained from table 4.1)

32. Residue Specification
Cool sour gas to around 100 ⁰F upstream of the contactor
Do not exceed 120 ⁰F for the rich amine leaving the contactor
Maintain ⁰F difference between the two
Next section is corrosion in which we’ll see why this is important

33. Corrosion Keep amine solution clean (solids content below 0.1%)
Maintain ranges in previous slide
Operate still at lowest possible temperature (below 300 ⁰F)
Maintain a testing program (coupons and inhibitors)
Stress relief on all connections
Black, green or amber color in amine can indicate corrosion products

34. Foaming Common problem that will result in loss of treating capacity
Caused by contaminants in the amine solution
Avoid condensation of liquid hydrocarbons (temp above dew point)
Keep contactor clean (water wash or acidizing)
Run a reclaimer
Do not overload inlet separator (keeps out stuff from the field like corrosion inhibitors, soaps, etc.)
Carbon filter to adsorb liquid contaminants
If all else fails try a defoamer (use in a sample bottle first)

35. Amine Consumption
Certain amount will be lost in the process due to the vapor pressure of the amine
This should be the guideline for minimum consumption
Losses can be minimized by
Lowering the top temperature of the contactor
Water wash the top of the contactor
Use a good separator and mist eliminator on the contactor overhead
Carryover due to foaming and small leaks in the piping
Reaction with COS and CS2 cannot be regenerated and are removed in the reclaimer

36. Winterization System can freeze if down for long periods in winter
Amine concentration similar to the curve for glycol and will help avoid freezing