Gas Treating

INTRODUCTION

• Gas treating involves reduction of the “acid gases” carbon dioxide (CO2) and hydrogen sulfide (H2S), along with other sulfur species, to sufficiently low levels to meet contractual specifications or permit additional processing in the plant without corrosion and plugging problems.

PROBLEMS

• 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 and at concentrations greater than 1,000 ppmv, death occurs in minutes

• It is readily detectable at low concentrations by its “rotten egg” odor. Unfortunately, at toxic levels, it is odorless because it deadens nerve endings in the nose in a matter of seconds.

• When H2S concentrations are well above the ppmv level, other sulfur species can be present.

• These compounds include carbon disulfide (CS2), mercaptans (RSH), and sulfides (RSR), in addition to elemental sulfur.

• If CO2 is present as well, the gas may contain trace amounts of carbonyl sulfide (COS).

• The major source of COS typically is formation during regeneration of molecular-sieve beds used in dehydration.

Purification levels• The inlet conditions at a gas processing plant are generally

temperatures near ambient and pressures in the range of 300 to 1,000 psi (20 to 70 bar), so the partial pressures of the entering acid gases can be quite high.

• If the gas is to be purified to a level suitable for transportation in a pipeline and used as a residential or industrial fuel, then the H2S concentration must be reduced to 0.25 gr/100 scf (6 mg/m3) and the CO2 concentration must be reduced to a maximum of 3 to 4 mol%.

• However, if the gas is to be processed for NGL recovery or nitrogen rejection in a cryogenic turboexpander process, CO2 may have to be removed to prevent formation of solids.

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

Acid gas disposal

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

• Several gas plants exist to support CO2 flooding projects; the natural gas and NGL are valuable byproducts.

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

• In the case of H2S, four disposal options are available:1. Incineration and venting, if environmental regulations

regarding sulfur dioxide emissions can be satisfied2. Reaction with H2S scavengers, such as iron sponge3. Conversion to elemental sulfur by use of the Claus or

similar process4. Disposal by injection into a suitable underground

formation• The first two options are applicable to trace levels of

H2S in the gas, and the last two are required if concentrations are too high to make the first two options feasible

Purification process

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

1. CO2 removal from a gas that contains no H2S2. H2S removal from a gas that contains no CO23. Simultaneous removal of both CO2 and H2S4. Selective removal of H2S from a gas that

contains both CO2 and H2S

• Some of the more important items that must be considered before a process is selected are:• The type and concentration of impurities and hydrocarbon composition of the sour gas. For

example, COS, CS2, and mercaptans can affect the design of both gas and liquid treating facilities. Physical solvents tend to dissolve heavier hydrocarbons, and the presence of these heavier compounds in significant quantities tends to favor the selection of a chemical solvent.

• The temperature and pressure at which the sour gas is available. High partial pressures (50 psi [3.4 bar] or higher) of the acid gases in the feed favor physical solvents, whereas low partial pressures favor the amines.

• The specifications of the outlet gas (low outlet specifications favor the amines).• The volume of gas to be processed.• The specifications for the residue gas, the acid gas, and liquid products.• The selectivity required for the acid gas removal.• The capital, operating, and royalty costs for the process.• The environmental constraints, including air pollution regulations and disposal of byproducts

considered hazardous chemicals.• If gas sweetening is required offshore, both size and weight are additional factors that must

be considered. Whereas CO2 removal is performed offshore, H2S removal is rarely done unless absolutely necessary because of the problems of handling the rich acid gas stream or elemental sulfur.

SOLVENT ABSORPTION PROCESSES

Amines

• Amines are compounds formed from ammonia (NH3) by replacing one or more of the hydrogen atoms with another hydrocarbon group.

• Replacement of a single hydrogen produces a primary amine, replacement of two hydrogen atoms produces a secondary amine, and replacement of all three of the hydrogen atoms produces a tertiary amine.

• Primary amines are the most reactive, followed by the secondary and tertiary amines.

• 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.

Heats of Reaction

• The magnitude of the exothermic heats of reaction, which includes the heat of solution, of the amines with the acid gases is important because the heat liberated in the reaction must be added back in the regeneration step.

Process Flow Diagram• A typical diagram for the removal of acid gases from

natural gas by use of MEA• The sour gas feed enters the bottom of the contactor at

pressures to 1,000 psi (70 bar) and temperatures in the range of 90°F (32°C).

• The sour gas flows upward, countercurrent to the lean amine solution which flows down from the top. The lean amine that returns to the contactor is maintained at a temperature above the vapor that exits the contactor to prevent any condensation of heavier liquid hydrocarbons.

• The contactor operates above ambient temperature because of the combined exothermic heat of absorption and reaction.

• The maximum temperature is in the lower portion of the tower because the majority of the absorption and reaction occurs near the bottom of the unit.

• The temperature “bulge” in the tower can be up to about 180°F (80°C).

• The treated gas leaves the top of the tower water saturated and at a temperature controlled by the temperature of the lean amine that enters, usually around 100°F (38°C).

• The rich amine leaves the bottom of the unit at temperatures near 140°F (60°C) and enters a flash tank, where its pressure is reduced to 75 to 100 psig (5to 7 barg) to remove (flash) any dissolved hydrocarbons.

• The dissolved hydrocarbons are generally used as plant fuel. If necessary, a small stream of lean amine is contacted with the fuel gas to reduce the H2S concentration.

• The rich amine then passes through a heat exchanger and enters the solvent regenerator (stripper) at temperatures in the range of 180 to 220°F (80 to 105°C).

• The reboiler on the stripper generally uses low-pressure steam. The vapor generated at the bottom flows upward through either trays or packing, where it contacts the rich amine and strips the acid gases from the liquid that flows down.

• A stream of lean amine is removed from the stripper, cooled to about 110°F (45°C), and reenters the contactor at the top to cool and condense the upward-flowing vapor stream.

• The vapor, which consists mostly of acid gases and water vapor, exits the top of the stripper and is generally processed for sulfur recovery.

• The lean amine exits the bottom of the stripper at about 260°F (130°C) and is pumped to the contactor pressure, exchanges heat with the rich amine stream, and is further cooled before it enters the top of the contactor.

• Both the treated gas that leaves the gas contactor and the acid gas to the Claus unit are water saturated.

Amine Reclaiming• Amines react with CO2 and contaminants,

including oxygen, to form organic acids.• These acids then react with the basic amine to

form heat stable salts (HSS). • For MEA and DGA solutions, the salts are

removed through which utilizes a semicontinuous distillation

• The reclaimer is filled with lean amine, and a strong base, such as sodium carbonate or sodium hydroxide, is added to the solution to neutralize the heat stable salts.

• A slipstream of 1 to 3% of the circulating amine is then continuously added to the reclaimer while the mixture is heated.

• Water and amine vapor are taken off the top, which leaves the contaminants in the liquid bottoms.

• Heating is continued until the temperature is approximately 300°F (150°C) for MEA or 360 to 380°F (180 to 195°C) for DGA. The cycle is then stopped and the bottoms that contain the contaminants (dissolved salts, suspended solids) are removed.

• DEA does not form a significant amount of nonregenerable degradation products, and it requires more difficult reclaiming through vacuum distillation or ion exchange.

Operating Issues

• Corrosion—Some of the major factors that affect corrosion are:

1. Amine concentration (higher concentrations favor corrosion)

2. Rich amine acid gas loading (higher gas loadings in the amine favor corrosion)

3. Oxygen concentration4. Heat stable salts (higher concentrations

promote corrosion and foaming)

• Solution Foaming—Foaming of the liquid amine solution is a major problem

• because it results in poor vapor−liquid contact, poor solution distribution, and solution holdup with resulting carryover and off spec gas.

• Among the causes of foaming are suspended solids, liquid hydrocarbons, surface active agents, such as those contained in inhibitors and compressor oils, and amine degradation products, including heat stable salts.

• One obvious cure is to remove the offending materials; the other is to add antifoaming agents.

ALKALI SALTS• The hot potassium carbonate process for removing CO2

and H2S• Although the process was developed for the removal of

CO2, it can also remove H2S if H2S is present with CO2. • Special designs are required for removing H2S to

pipeline specifications or to reduce CO2 to low levels.• The process is very similar in concept to the amine

process, in that after physical absorption into the liquid, the CO2 and H2S react chemically with the solution. The chemistry is relatively complex, but the overall reactions are represented by

• In a typical application, the contactor will operate at approximately 300 psig (20 barg), with the lean carbonate solution entering near 225°F (110°C) and leaving at 240°F (115°C).

• The rich carbonate pressure is reduced to approximately 5 psig (0.3 barg) as it enters the stripper.

• Approximately one third to two thirds of the absorbed CO2 is released by the pressure reduction, reducing the amount of steam required for stripping (Kohl and Nielsen, 1997).

• The lean carbonate solution leaves the stripper at the same temperature as it enters the contactor, and eliminates the need for heat exchange between the rich and lean streams.

• The heat of solution for absorption of CO2 in potassium carbonate is small, approximately 32 Btu/cu ft of CO2 and consequently the temperature rise in the contactor is small and less energy is required for regeneration.

PHYSICAL ABSORPTION

• In the amine and alkali salt processes, the acid gases are removed in two steps:

• Physical absorption followed by chemical reaction. • In processes such as Selexol or Rectisol, no chemical

reaction occurs and acid gas removal depends entirely on physical absorption. Some of the inherent advantages and disadvantages of physical absorption processes are summarized below:

1. Absorption processes are generally most efficient when the partial pressures of the acid gases are relatively high, because partial pressure is the driving force for the absorption.

2. 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.

3. Solvents can be chosen for selective removal of sulfur compounds, which allows CO2 to be slipped into the residue gas stream and reduce separation costs.

4. Energy requirements for regeneration of the solvent are lower than in systems that involve chemical reactions.

5. Separation can be carried out at near-ambient temperature.6. Partial dehydration occurs along with acid gas removal,

whereas amine processes produce a water saturated product stream that must be dried in most applications.

SOLVENT PROPERTIES• Selexol is a polyethylene glycol and has the

general formula: CH3—O—CH2—(CH2—O—CH2)N—CH2—O—CH3

• The plant is designed to process 26 MMscfd (0.74 MMSm3/d) entering the Selexol unit at 603 psia (41.6 bar) and 32°F (0°C).

• The lean solvent, cooled to 25°F (−3.9°C) with propane refrigerant, enters the absorber where it absorbs CO2 and some of the ethane and heavier hydrocarbons.

• The rich solvent from the absorber is regenerated by reduction of the pressure in three flash drums, from 603 to 106 psia (41.6 to 7.3 bar) in the high-pressure drum, from 106 to 16 psia (7.3 to 1.1 bar) in the medium-pressure drum, and from 16 to 3 psia (1.1 to 0.21 bar) in the vacuum drum.

• Lean Selexol from the vacuum drum is recompressed and sent to the propane chiller. The treated gas that leaves the absorber passes through a knockout drum and filter separator to remove entrained Selexol and condensed hydrocarbons.

• The treated gas meets the specifications of a maximum of 0.50% CO2 and a maximum of 6.5% ethane and heavier hydrocarbons.

• In addition, the water content of the gas is reduced from 75 ppmv to 12 ppmv, H2S is reduced from 2 ppmv to essentially nothing, and methyl mercaptan is reduced from 5 ppmv to 1 ppmv.

• Unlike the amine systems, no irreversible products are generated in the process, which thus eliminates the need for reclaiming.

ADSORPTION

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

• Applications are limited because water displaces acid gases on adsorbent bed.

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

• However, this reduction requires regeneration of the bed at 600°F (315°C) for extended time with the potential for COS formation if 4A* is used.

• The flow configuration shows the first bed in the adsorption cycle, the second bed cooling down after regeneration, and the third bed undergoing regeneration with hot gas.

CRYOGENIC FRACTIONATION

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

• Problems are associated with the separation of CO2 from methane, CO2 from ethane, and CO2 from H2S.

CO2 from methane: Relative volatilities (KC1/KCO2) at typical distillation conditions are about 5 to 1. Maximum-vapor concentration of methane is only 85 to 90 mol%.

CO2 from ethane: In addition to solidification problems, CO2 and ethane form an azeotrope (liquid and vapor compositions are equal) and appears at approximately 0.6 mole fraction of CO2.

CO2 from H2S: This distillation is difficult because, mixture forms a pinch at high CO2 concentrations. This separation by conventional distillation is complicated by the need to have an overhead product that has roughly 100 ppmv H2S if the stream is vented. The bottoms product should contain less than two-thirds CO2, assuming the stream is feed to a Claus unit