1. Natural Gas Production Chapter 6 Misc. Gas Conditioning
PTRT 2323
Natural Gas Production
Chapter 6
Misc. Gas Conditioning

2. Gas Conditioning
H2S and CO2 are called acid gases since they form acids in presence of water vapor
H2S pipeline specification typically 4 ppm
CO2 not always required but doesn’t burn so pipeline spec typically 2%
Pipeline spec requires minimum heating value (BTU/cf)
4ppm = 0.25 grains elemental sulfur includes all forms of sulfur not just H2S

3. Removing Acid Gases Iron sponge – oldest but most limited technique
Fe2O3 impregnated wood chips or shavings
Regenerates partially using hot air
Alkanolamine Process – Amine Plant
Continuous
Liquid process
Absorption
Thermal regeneration
Biomass reactor

4. Iron Sponge Sweetening
Used for decades to treat industrial gases
Batch process
< 120 F to allow for presence of water allows chemistry to proceed
Bed can be regenerated
Sulfur eventually fouls the bed and it must be replaced

5. Iron Sponge Sweetening
Applicable for:
Small gas volumes
Low H2S content
Selective for H2S
No CO2 removal
Primary disadvantage is change-out of the bed

6. Alkanolamine Sweetening
Monoethanolamine (MEA)
Diethanolamine (DEA)
Triethanolamine (TEA)
Non-selective – remove BOTH H2S and CO2
Weak acid (H2S and CO2) reacts with weak base (MEA, DEA or TEA) to produce a soluble salt

7. Alkanolamine Sweetening
and
In regeneration:

8. Alkanolamine Sweetening
DEA
Above 125 psia most common
lower circulation rates are possible
Less energy required for regeneration
Below 50 psia DEA will not remove enough H2S
MEA most common for low P applications
COS (carbonyl sulfide) is a problem in refineries during regeneration but not typically a natural gas field issue

9. Basic Process Similarity to glycol system obvious
Critical to remove separable liquids prior to absorption process
Sour gas rises counter-current to the descending amine solution (50:50 mix)
Sweet gas exits the top of the contactor
Amine regeneration uses a still

10. Basic Process Gas Sweetening

11. Basic Process
Amine Regeneration

12. Basic Process
Amine Distillation

13. Amine Regeneration Rich amine flash tank Heat exchanger T> 190 F
Absorbed gases removed by pressure drop
Evolved gases are flared (SO2)
Heat exchanger T> 190 F
Regeneration still heated by steam rising counter-current to rich amine
Heat shifts equilibrium and liberates H2S and CO2 from the amine solution
Final cooling of the now lean amine done with cooling tower

14. Glycol/Amine Process
Combines dehydration and sweetening with mixture of treatment chemicals
10-30% MEA
45-85% Glycol
5-25% water
Removes water, H2S and CO2 simultaneously
Lower equipment costs

15. Disadvantages
Extra losses of MEA caused by higher regeneration temperatures required
Reprocessing requires vacuum distillation
Complex corrosion problems that can be plant specific
ONLY for gas streams that do NOT require low dew points

16. Sulfinol Process Mixture of solvents (Shell proprietary) Advantages
Low circulation rates
Smaller plant size
Low heat capacity of solvent (easier to heat)
Low utility costs
Low degradation rates
Low corrosion rates
Low foaming
Effective on other sulfur compounds (COS, CS2 and mercaptans)
Low vaporization losses
Low fouling of heat exchanger
Small expansion during freezing
Disadvantages
Absorption of heavier hydrocarbons
Expense of solvent
Proprietary to Shell (royalty payment)

17. BTU Control
As more ethane and propane are removed from the gas stream BTU control becomes important
Caution must be taken to avoid inert components (CO2, N2) or BTU content will be too low.
Limits amount of ethane and propane that can be removed
Mixing low BTU gas with high BTU gas is an option
BTU content is measured with a calorimeter