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

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

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

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

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

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

Alkanolamine Sweetening and In regeneration:

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

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

Basic Process Gas Sweetening

Basic Process Amine Regeneration

Basic Process Amine Distillation

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

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

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

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)

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