PROPERTIES OF NATURAL GAS

Treated natural gas consists mainly of methane; the properties of both
gases (natural gas and methane) are nearly similar. However, natural gas
is not pure methane, and its properties are modified by the presence of
impurities, such as N2 and CO2 and small amounts of unrecovered heavier
hydrocarbons.
An important property of natural gas is its heating value. Relatively
high amounts of nitrogen and/or carbon dioxide reduce the heating value
of the gas. Pure methane has a heating value of 1,009 Btu/ft3. This value
is reduced to approximately 900 Btu/ft3 if the gas contains about 10% N2
and CO2. (The heating value of either nitrogen or carbon dioxide is zero.)
On the other hand, the heating value of natural gas could exceed
methane’s due to the presence of higher-molecular weight hydrocarbons,
which have higher heating values. For example, ethane’s heating value is
1,800 Btu/ft3, compared to 1,009 Btu/ft3 for methane. Heating values of
hydrocarbons normally present in natural gas are shown in Table 1-4.
Natural gas is usually sold according to its heating values. The heating
value of a product gas is a function of the constituents present in the mixture.
In the natural gas trade, a heating value of one million Btu is
approximately equivalent to 1,000 ft3 of natural gas.

Water Removal

Moisture must be removed from natural gas to reduce corrosion problems
and to prevent hydrate formation.
Hydrates are solid white compounds
formed from a physical-chemical reaction between hydrocarbons
and water under the high pressures and low temperatures used to transport
natural gas via pipeline. Hydrates reduce pipeline efficiency.
To prevent hydrate formation, natural gas may be treated with glycols,
which dissolve water efficiently. Ethylene glycol (EG), diethylene glycol
(DEG), and triethylene glycol (TEG) are typical solvents for water
removal. Triethylene glycol is preferable in vapor phase processes
because of its low vapor pressure, which results in less glycol loss. The
TEG absorber normally contains 6 to 12 bubble-cap trays to accomplish
the water absorption. However, more contact stages may be required to
reach dew points below –40°F. Calculations to determine the number of
trays or feet of packing, the required glycol concentration, or the glycol
circulation rate require vapor-liquid equilibrium data. Predicting the interaction
between TEG and water vapor in natural gas over a broad range
allows the designs for ultra-low dew point applications to be made.6
A computer program was developed by Grandhidsan et al., to estimate
the number of trays and the circulation rate of lean TEG needed to dry natual
gas. It was found that more accurate predictions of the rate could be
achieved using this program than using hand calculation.7
Figure 1-4 shows the Dehydrate process where EG, DEG, or TEG
could be used as an absorbent.8 One alternative to using bubble-cap trays
is structural packing, which improves control of mass transfer. Flow passages
direct the gas and liquid flows countercurrent to each other. The use
of structural packing in TEG operations has been reviewed by Kean et al.9
Another way to dehydrate natural gas is by injecting methanol into gas
lines to lower the hydrate-formation temperature below ambient.10 Water
can also be reduced or removed from natural gas by using solid adsorbents
such as molecular sieves or silica gel.
Condensable Hydrocarbon Recovery
Hydrocarbons heavier than methane that are present in natural gases
are valuable raw materials and important fuels. They can be recovered by
lean oil extraction. The first step in this scheme is to cool the treated gas
by exchange with liquid propane. The cooled gas is then washed with a
cold hydrocarbon liquid, which dissolves most of the condensable hydrocarbons.
The uncondensed gas is dry natural gas and is composed mainly
of methane with small amounts of ethane and heavier hydrocarbons. The
condensed hydrocarbons or natural gas liquids (NGL) are stripped from
the rich solvent, which is recycled. Table 1-2 compares the analysis of
natural gas before and after treatment.11 Dry natural gas may then be
used either as a fuel or as a chemical feedstock.
Another way to recover NGL is through cryogenic cooling to very low
temperatures (–150 to –180°F), which are achieved primarily through
adiabatic expansion of the inlet gas. The inlet gas is first treated to
remove water and acid gases, then cooled via heat exchange and refrigeration.
Further cooling of the gas is accomplished through turbo
expanders, and the gas is sent to a demethanizer to separate methane
from NGL. Improved NGL recovery could be achieved through better
control strategies and use of on-line gas chromatographic analysis.12

NATURAL GAS TREATMENT PROCESSES

Raw natural gases contain variable amounts of carbon dioxide, hydrogen
sulfide, and water vapor. The presence of hydrogen sulfide in natural
gas for domestic consumption cannot be tolerated because it is poisonous.
It also corrodes metallic equipment. Carbon dioxide is undesirable,
because it reduces the heating value of the gas and solidifies under the
high pressure and low temperatures used for transporting natural gas. For
obtaining a sweet, dry natural gas, acid gases must be removed and water
vapor reduced. In addition, natural gas with appreciable amounts of heavy
hydrocarbons should be treated for their recovery as natural gas liquids.
Acid Gas Treatment
Acid gases can be reduced or removed by one or more of the following
methods:
1. Physical absorption using a selective absorption solvent.
2. Physical adsorption using a solid adsorbent.
3. Chemical absorption where a solvent (a chemical) capable of reacting
reversibly with the acid gases is used.
Physical Absorption
Important processes commercially used are the Selexol, the Sulfinol,
and the Rectisol processes. In these processes, no chemical reaction
occurs between the acid gas and the solvent. The solvent, or absorbent, is
a liquid that selectively absorbs the acid gases and leaves out the hydrocarbons.
In the Selexol process for example, the solvent is dimethyl ether
of polyethylene glycol. Raw natural gas passes countercurrently to the
descending solvent. When the solvent becomes saturated with the acid
gases, the pressure is reduced, and hydrogen sulfide and carbon dioxide
are desorbed. The solvent is then recycled to the absorption tower.
Physical Adsorption
In these processes, a solid with a high surface area is used. Molecular
sieves (zeolites) are widely used and are capable of adsorbing large
amounts of gases. In practice, more than one adsorption bed is used for
continuous operation. One bed is in use while the other is being regenerated Regeneration is accomplished by passing hot dry fuel gas through the
bed. Molecular sieves are competitive only when the quantities of hydrogen
sulfide and carbon disulfide are low.
Molecular sieves are also capable of adsorbing water in addition to the
acid gases.
Chemical Absorption (Chemisorption)
These processes are characterized by a high capability of absorbing
large amounts of acid gases. They use a solution of a relatively weak
base, such as monoethanolamine. The acid gas forms a weak bond with
the base which can be regenerated easily. Mono- and diethanolamines are
frequently used for this purpose. The amine concentration normally
ranges between 15 and 30%. Natural gas is passed through the amine
solution where sulfides, carbonates, and bicarbonates are formed.
Diethanolamine is a favored absorbent due to its lower corrosion rate,
smaller amine loss potential, fewer utility requirements, and minimal
reclaiming needs.3 Diethanolamine also reacts reversibly with 75% of
carbonyl sulfides (COS), while the mono- reacts irreversibly with 95% of
the COS and forms a degradation product that must be disposed of.
Diglycolamine (DGA), is another amine solvent used in the
Econamine process (Fig 1-2).4 Absorption of acid gases occurs in an
absorber containing an aqueous solution of DGA, and the heated rich solution (saturated with acid gases) is pumped to the regenerator.
Diglycolamine solutions are characterized by low freezing points, which
make them suitable for use in cold climates.
Strong basic solutions are effective solvents for acid gases. However,
these solutions are not normally used for treating large volumes of natural
gas because the acid gases form stable salts, which are not easily
regenerated. For example, carbon dioxide and hydrogen sulfide react
with aqueous sodium hydroxide to yield sodium carbonate and sodium
sulfide, respectively.
CO2 + 2NaOH (aq) r Na2 CO3 + H2O
H2S + 2 NaOH (aq) r Na2S + 2 H2O
However, a strong caustic solution is used to remove mercaptans from
gas and liquid streams. In the Merox Process, for example, a caustic solvent
containing a catalyst such as cobalt, which is capable of converting
mercaptans (RSH) to caustic insoluble disulfides (RSSR), is used for
streams rich in mercaptans after removal of H2S. Air is used to oxidize
the mercaptans to disulfides. The caustic solution is then recycled for
regeneration. The Merox process (Fig. 1-3) is mainly used for treatment
of refinery gas streams .