Gas Treating

Gas treating involves reduction of the “acid gases” carbon dioxide (CO2) and hydrogen sulfide (H2S), along with other sulfur species, to sufficiently low levels.

Purpose: To meet contractual specifications or permit additional processing in the plant without corrosion and plugging problems

1. Why are the acid gases a problem?

2. What are the acid gas concentrations in natural gas?

3. How much purification is needed?

4. What is done with the acid gases after separation from the natural gas?

5. What processes are available for acid gas removal?

Hydrogen sulfide is highly toxic, and in the presence of water it forms a weak, corrosive acid.

The threshold limit value (TLV) for prolonged exposure is 10 ppmv

At concentrations greater than 1,000 ppmv, death occurs in minutes

Carbon dioxide is nonflammable and, consequently, large quantities are undesirable in a fuel.

Like H2S, it forms a weak, corrosive acid in the presence of water.

The Problem

CO2 ≥ 2%

N2 ≥ 4%

H2S ≥ 4 ppmv.

ACID GAS CONCENTRATIONS IN NATURAL GAS

H2S concentration must be reduced to 0.25 gr/100 scf (6 mg/m3)

CO2concentration must be reduced to a maximum of 3 to 4 mol%

If the gas is being fed to an LNG liquefaction facility, then the maximum CO2 level is about 50 ppmv

Purification Levels

For CO2, if the quantities are large, it is sometimes used as an injection fluid in EOR (enhanced oil recovery) projects

If this option is unavailable, then the gas can be vented, provided it satisfies environmental regulations for impurities

Acid Gas Disposal

In the case of H2S, four disposal options are available:

1. Incineration and venting, if environmental regulations regarding sulfur dioxide emissions can be satisfied

2. Reaction with H2S scavengers, such as iron sponge

3. Conversion to elemental sulfur by use of the Claus or similar process

4. Disposal by injection into a suitable underground formation

Four scenarios are possible for acid gas removal from natural gas:

1. CO2 removal from a gas that contains no H2S 2. H2S removal from a gas that contains no CO2

3. Simultaneous removal of both CO2 and H2S

4. Selective removal of H2S from a gas that contains both CO2 and H2S

PURIFICATION PROCESSES

Acid Gas Removal Processes

Some of the more important items that must be considered before a process is selected:

The type and concentration of impurities and hydrocarbon composition of the sour gas

The temperature and pressure at which the sour gas is available

The specifications of the outlet gas

The volume of gas to be processed

The capital and operating costs for the process

The environmental constraints, including air pollution regulations and disposal of byproducts considered hazardous chemicals

Process Selection Chart For CO2 Removal With No H2S Present

Process Selection Chart For H2S Removal With No CO2 Present

Process Selection Chart For Simultaneous H2S And CO2 Removal

Process Selection Chart For Selective H2S Removal With CO2 Present

In solvent absorption, the two major cost factors are the solvent circulation rate, which affects both equipment size and operating costs, and the energy requirement for regenerating the solvent

Amines: Amines are compounds formed from ammonia (NH3)

Amines remove H2S and CO2 in a two step process:

1. The gas dissolves in the liquid (physical absorption).

2. The dissolved gas, which is a weak acid, reacts with the weakly basic amines.

SOLVENT ABSORPTION PROCESSES

Monoethanolamine (MEA) is the most basic of the amines used in acid treating.DiglycolamineDiethanolamine(DEA)MethyldiethanolamineSterically Hindered AminesMixed Amines

Amine Treating using MEA

Corrosion

Solution Foaming: Foaming of the liquid amine solution is a major problem because it results in poor vapor−liquid contact

Heat stable salts (higher concentrations promote corrosion and foaming)

Operating Issues

Hot Potassium Carbonate Process

Physical absorption(selexol)

Advantages and disadvantages of physical absorption processes

Absorption processes are generally most efficient when the partial pressures of the acid gases are relatively high

Heavy hydrocarbons are strongly absorbed by the solvents used, and consequently acid gas removal is most efficient in natural gases with low concentrations of heavier hydrocarbons

Separation can be carried out at near-ambient temperature

Partial dehydration occurs along with acid gas removal, whereas amine processes produce a water saturated product stream that must be dried in most applications

Physical Absorption

Acid gases, as well as water, can be effectively removed by physical adsorption on synthetic zeolites

Applications are limited because water displaces acid gases

Molecular sieve can reduce H2S levels to the 0.25 gr/100 scf (6 mg/ m3) specification.

ADSORPTION

Natural Gas Desulfurization Plant

Distillation is the most widely used process to separate liquid mixtures, and it seems a good prospect for removing CO2 and H2S from natural gas

However, problems are associated with the separation of CO2 from methane, CO2 from ethane and CO2 from H2S

CO2 from methane: Relative volatilities (KC1/K CO2) at typical distillation conditions are about 5 to 1.

Cryogenic Fractionation

CO2 from ethane: In addition to solidification problems, CO2 and ethane form an azeotrope (liquid and vapor compositions are equal) and consequently, a complete separation of those two by simple distillation is impossible

CO2 from H2S : This distillation is difficult because, the mixture forms a pinch at high CO2 concentrations.

Membranes are used in natural gas processing for dehydration and bulk CO2 removal

The driving force for movement through the membrane is the difference in chemical potential, µ, for a given component on the two sides of the membrane

Membranes

Membrane used : Cellulose acetate

A thin layer of cellulose acetate is on top of a thicker layer of a porous support material

Permeable compounds dissolve into the

membrane, diffuse across it, and then travel through the inactive support material

The membranes are thin to maximize mass transfer and, thus, minimize surface area and cost

Carbon Dioxide Removal from Natural Gas

Low Pressure, Bore-side Gas Feed Module

It is a countercurrent flow configuration similar to a shell-tube heat exchanger with the gas entering on the tube side

More resistant to fouling because the inlet gas flows through the inside of the hollow fibers

However, the mechanical strength of the membrane limits the pressure drop across the membrane

To handle high pressures, the permeate flows into the hollow fiber from the shell side

This feature makes the membrane much more susceptible to plugging, and gas pretreatment is usually required

Process

Flow pattern: Depends on the process

Flow Rate: A maximum acceptable feed gas rate per unit area applies to the membrane

Operating Temperature: Increased operating temperature increases permeability

Operating Pressure: Increased feed pressure decreases both the permeability

Feed Gas Pretreatment: Because membranes are susceptible to degradation from impurities, pretreatment is usually required

Operating Considerations

Low capital investment when compared with solvent systems

Ease of installation Good weight and space efficiency

Economy of scale Clean feed

Advantages and Disadvantagesof Membrane Systems

When the quantity of sulfur to be recovered is small, on the order of 400 lb/d(180 kg/d) or less, small-scale batch processes are used for H2S removal

These processes generally use a nonregenerable scavenger

Ex: Iron-sponge bed

Nonregenerable HydrogenSulfide Scavengers

The gas stream that contains the H2S is first absorbed into a mild alkaline solution

Absorbed sulfide is oxidized to elemental sulfur by naturally occurring microorganisms

Biological Processes

H2S leaks

Solvent Absorption: The solvent may be hazardous or toxic

Iron Bed: Respiratory and eye irritants

Safety and EnvironmentalConsiderations