Speight J.G. Natural Gas: A Basic Handbook
Подождите немного. Документ загружается.
5.2
Natural
Gas
129
resulted
in
an ever-increasingly stable, consistent, and functional
end-use product. Thus, one of the first steps in improving the quality
of
the natural gas was the removal
of
the natural gas liquids.
Natural gas liquids are recovered using four different technologies:
refrigeration, cryogenic recovery,
oil
absorption,
and
dry-bed adsorption.
Natural gas liquids are recovered by cooling or refrigerating the nat-
ural gas until the liquids are condensed out.
Cryogenic recovery
pro-
cesses are done at temperatures lower than
-150
OF.
The low
temperatures allow the plant to recover more than
90%
of
the ethane
in
the natural gas. Most new gas processing plants use cryogenic
recovery technology.
Oil absorption
is a process used by older gas pro-
cessing plants and
in
many refinery gas plants, and there have been
some changes
in
the focus
in
terms
of
the use
of
these processes as the
twentieth century aged (Figure
5-3).
Over the past thirty years, the oil and natural gas industry has been
transformed into one
of
the most technologically advanced industries
in
the United States. New innovations have reshaped the industry
into a technology leader,
in
all segments
of
the industry.
In
recent
years, demand
for
natural gas has grown substantially. However, as
the natural gas industry in the United States becomes more mature,
domestically available resources become harder to find and produce.
As
large, conventional natural gas deposits are extracted, the natural
gas left in the ground is commonly found in less conventional
deposits, which are harder to discover and produce than has histori-
cally been the case. However, the natural gas industry has been able
Figure
5-3
Evolution
of
gas processing.
130
Chapter
5
History of Gas Processing
to keep pace with demand, and produce greater amounts
of
natural
gas despite the increasingly unconventional and elusive nature. The
ability
of
the industry to increase production in this manner has been
a
direct result
of
technological innovations.
5.3
References
Davidson, W.B.,
1913,
Chem. Trade Journal.
52:
769.
Higman,
C.
and Van Der Burgt,
M.,
2003,
Gasification,
Butterworth
Heinemann, Oxford, England.
Murphy,
B.L.,
Sparacio, T., Walter,
J.,
Shields, W.J.,
2005,
Environmental
Forensics,
6(2): 161.
Speight,
J.G.,
1993,
Gas Processing: Environmental Aspects and Methods,
Butterworth Heinemann, Oxford, England.
Speight, J.G.,
1994,
The
Chemistry and Technology of Coal,
Znd
Edition, Marcel
Dekker Inc., New York.
Stewart, E.G.,
1958,
Town Gas:
Its
Manufacture and Distn’bution,
H.M.
Stationery Office, London, England.
Sugg, W.T.,
1884,
The Domestic Uses of Coal Gas,
Walter King,
London,
England.
Tristan,
F.,
1840,
Promenades Duns Londres,
trans. Palmer, D, and Pincetl, G.
(1980)
Flora Tristan’s London Journal,
A
Survey
of
London Life in the
1830s,
George Prior, Publishers,
London;
extract,
Worse Than the Slave Trade
in
Appendix
1,
Barty-King,
H
(1985).
CHAPTER
6
Process
Classification
Various types of processing plants have been used since the mid-
1850s
to extract liquids, such as natural gasoline, from produced
crude oil. However, for many years, natural gas was not a desired fuel.
Prior to the early 20thcentury, most
of
it was flared or simply vented
into the atmosphere, primarily because the available pipeline tech-
nology permitted only very short-distance transmission.
As
the gas processing industry evolved (Chapter
5),
the natural gas
received and transported by the major intrastate and interstate main-
line transmission systems in the United States had to meet the quality
standards specified by pipeline companies. These quality standards
vary from pipeline to pipeline and are usually a function
of
a pipeline
system’s design, its downstream interconnecting pipelines, and its
customer base. However, these standards generally specify that the
natural gas must:
1.
2.
3.
4.
Be within a specific
Btu
content range
(1,035
Btu/ft3,
+/-
50
Btu)
Be delivered at a specified hydrocarbon dew-point
temperature level (below which any vaporized gas liquid
in
the mix will tend to condense at pipeline pressure)
Contain
no
more than trace amounts
of
elements such as
hydrogen sulfide, carbon dioxide, nitrogen, water vapor, and
oxygen
Be free
of
particulate solids and liquid water that could be
detrimental to the pipeline or its ancillary operating
equipment
131
132
Chauter
6
Process Classification
Gas processing equipment, whether in the field
or
at processing/treat-
ment plants, assures that these requirements can be met. While
in
most cases processing facilities extract contaminants and higher
molecular weight hydrocarbons (natural gas liquids) from the gas
stream. However,
in
some cases, the higher molecular weight
hydrocarbons may be blended into the gas stream
to
bring it within
acceptable Btu levels. Whatever the situation, there is the need to pre-
pare the gas for transportation and use in domestic and commercial
furnaces. Thus, natural gas processing begins at the wellhead and
because the composition
of
the raw natural gas extracted from pro-
ducing wells depends
on
the type, depth, and location of the under-
ground deposit and the geology
of
the area, processing must offer
several options (even though each option may be applied
to
a dif-
ferent degree) to accommodate the difference in composition
of
the
extracted gas (Figure 6-1).
In
those few cases where pipeline-quality natural gas is actually pro-
duced at the wellhead or field facility, the natural gas is moved
directly to the pipeline system.
In
other instances, especially in the
production
of
non-associated natural gas, field or lease facilities
referred
to
as
skid-mount plants
are installed nearby to dehydrate
(remove water) and decontaminate (remove dirt and other extra-
neous materials) raw natural gas into acceptable pipeline-quality gas
for direct delivery to the pipeline system. The
skids
are often specifi-
cally customized to process the type of natural gas produced
in
the
area and are a relatively inexpensive alternative to transporting the
natural gas to distant large-scale plants for processing.
Gas processing (Mokhatab et al., 2006) consists
of
separating all
of
the
various hydrocarbons, non-hydrocarbons (such as carbon dioxide
and hydrogen sulfide), and fluids from the methane (Table 6-1).
Major transportation pipelines usually impose restrictions
on
the
make-up
of
the natural gas that is allowed into the pipeline. That
means that before the natural gas can be transported it must be puri-
fied. While the ethane, propane, butanes, and pentanes must be
removed from natural gas, this does not mean that they are all waste
products.
Gas processing (gas refining)
is
necessary to ensure that the natural
gas intended for use is clean-burning and environmentally accept-
able. Natural gas used by consumers is composed almost entirely
of
methane, but natural gas that emerges from the reservoir at the
well-
head is by
no
means as
pure
(Chapter
3).
Although the processing
of
133
Figure
6-1
General schematic
of
gas
processing.
Table
6-1
Range
of
Composition
of
Natural Gas
Methane
Ethane CZH,
0-20%
Propane
C,H*
Butane
C4H10
Pentane and higher hydrocarbons
C5HlZ
O-lOYO
Carbon dioxide CO,
04%
Oxygen
0,
M.2%
Nitrogen NZ
04%
Hydrogen sulfide, carbonyl sulfide
H,S,
COS
04%
Rare
gases: Argon, Helium, Neon, Xenon
A,
He, Ne, Xe trace
134
Chapter
6
Process Classification
natural gas is in many respects less complicated than the processing
and refining of crude oil, it is equally as necessary before its use by
end users.
Raw natural gas comes from three types of wells: oil wells, gas wells,
and condensate wells (Chapter
2
and Chapter
4).
Associated
gas
(Chapter
l),
i.e., gas from petroleum wells, can exist separate from oil
in
the formation (free gas),
or
dissolved in the crude oil (dissolved
gas).
Non-associated
gas,
i.e., gas from gas wells or condensate wells is
pee
natural gas along with a semi-liquid hydrocarbon condensate.
Whatever the source
of
the natural gas, once separated from crude oil
(if
present) it commonly exists
in
mixtures with other hydrocarbons;
principally ethane, propane, butane, and pentanes.
In
addition, raw
natural gas contains water vapor, hydrogen sulfide
(H,S),
carbon
dioxide, helium, nitrogen, and other compounds.
In
fact, the associ-
ated hydrocarbons
(natural
gas
liquids,
NGLs) can be valuable by-
products
of
natural gas processing. Natural gas liquids include ethane,
propane, butane, iso-butane, and natural gasoline, which are sold
separately and have a variety
of
different uses; including enhancing
oil recovery in oil wells, providing raw materials for oil refineries or
petrochemical plants, and as sources
of
energy.
The actual practice
of
processing natural gas to high-quality pipeline
gas for the consumer usually involves four main processes to remove
the various impurities:
1.
Water removal
2.
Liquids removal
3.
Enrichment
4.
Fractionation
5.
The process by which hydrogen sulfide is converted to sulfur
(the
Claus
process)
The processes that have been developed to accomplish gas purifica-
tion vary from a simple once-through wash operation to complex
multi-step recycling systems (Speight,
1993;
Mokhatab et al.,
2006).
In
many cases, the process complexities arise because of the need for
recovery of the materials used to remove the contaminants or even
recovery
of
the contaminants in the original, or altered, form (Katz,
1959;
Kohl and Riesenfeld,
1985;
Newman.
1985).
135
However, the processes applied to gas processing are subject
to
several
variables that must,
of
necessity be considered:
1.
The types
of
contaminants in the gas
2.
The concentrations
of
contaminants in the gas
3.
The degree of contaminant removal desired
4.
The selectivity
of
acid gas removal required
5.
The temperature of the gas to be processed
6.
The pressure
of
the gas
to
be processed
7.
The volume
of
the gas to be processed
8.
The composition
of
the gas to be processed
9.
The carbon dioxide-hydrogen sulfide ratio
in
the gas
10.
The desirability
of
sulfur recovery due to process economics or
environmental issues
In addition to hydrogen sulfide
(H,S)
and carbon dioxide
(CO,),
gas
may contain other contaminants, such as mercaptans
(RSH)
and car-
bony1 sulfide
(COS).
The presence of these impurities may eliminate
some of the sweetening processes because some processes remove
large amounts
of
acid gas but not to a sufficiently low concentration.
On
the other hand, some processes are not designed
to
remove (or are
incapable
of
removing) large amounts
of
acid gases. However, these
processes are also capable of removing the acid gas impurities
to
very
low levels when the acid gases are
in
low
to
medium concentrations
in
the gas.
Process selectivity indicates the preference with which the process
removes one acid gas component relative to (or in preference to)
another.
For
example, some processes remove both hydrogen sulfide
and carbon dioxide, while other processes are designed to remove
hydrogen sulfide only. It is important to consider the process selec-
tivity for, say, hydrogen sulfide removal compared to carbon dioxide
removal, which ensures minimal concentrations
of
these components
in the product, and thus requires one to consider the carbon dioxide
to hydrogen sulfide ratio in the gas stream (Nonhebel,
1964;
Curry,
1981;
Maddox,
1982;
Soud and Takeshita,
1994).
136
Chapter
6
Process Classification
Initially, natural gas receives a degree of cleaning at the wellhead. The
extent
of
the cleaning depends upon the specification that the gas
must meet to enter the pipeline system. For example, natural gas
from high-pressure wells is usually passed through field separators at
the well to remove hydrocarbon condensate and water. Natural gaso-
line, butane, and propane are usually present in the gas, and gas pro-
cessing plants are required for the recovery of these liquefiable
constituents.
Throughout this chapter,
two
terms are used frequently:
absorption
and
adsorption.
Absorption
is an approach
in
which the absorbed gas is ultimately dis-
tributed throughout the absorbent (liquid). The process depends only
on physical solubility and may include chemical reactions in the
liquid phase
(chernisorption).
Common absorbing media are water,
aqueous amine solutions, caustic, sodium carbonate, and nonvolatile
hydrocarbon oils, depending on the type of gas to be absorbed. Usu-
ally, the gas-liquid contactor designs are plate columns or packed beds.
Absorption is achieved by dissolution (a physical phenomenon) or by
reaction (a chemical phenomenon) (Barbouteau and Galaud, 1972;
Ward, 1972). Chemical adsorption processes adsorb sulfur dioxide
onto a carbon surface where it is oxidized (by oxygen in the flue gas)
and absorbs moisture to give sulfuric acid impregnated into and
on
the adsorbent.
Adsorption
differs from
absorption
in that it is a physical-chemical phe-
nomenon in which the gas is concentrated on the surface
of
a solid or
liquid to remove impurities (Mantell, 1951). Usually, carbon is the
adsorbing medium (Rook, 1994), which can be regenerated upon
des-
orption
(Fulker, 1972; Speight, 1993). The quantity of material
adsorbed is proportional to the surface area
of
the solid and, conse-
quently, adsorbents are usually granular solids with a large surface
area per unit mass. Subsequently, the captured gas can be desorbed
with hot air
or
steam either for recovery or for thermal destruction.
The number
of
steps and the type
of
process used to produce pipeline-
quality natural gas most often depends upon the source and makeup
of
the wellhead production stream.
In
some cases, several
of
the steps
(Figure
6-1)
may
be
integrated
into
one
unit
or operation, performed
in a different order or at alternative locations, or not required at all.
6.1
Water Removal
13
7
In
many instances pressure relief at the wellhead will cause a natural
separation of gas from oil (using a conventional closed tank, where
gravity separates the gas hydrocarbons from the higher boiling crude
oil).
In
some cases, however, a multi-stage gas-oil separation process is
needed to separate the gas stream from the crude oil. These
gas-oil
sep-
arators
are commonly closed cylindrical shells, horizontally mounted
with inlets at one end, an outlet at the top
for
removal of gas, and an
outlet at the bottom for removal
of
oil. Separation is accomplished by
alternately heating and cooling (by compression) the flow stream
through multiple steps; some water and condensate,
if
present, will
also be extracted as the process proceeds.
At some stage
of
the processing, the gas flow is directed to a unit that
contains a series
of
filter tubes.
As
the velocity of the stream reduces in
the unit, primary separation of remaining contaminants occurs due to
gravity. Separation
of
smaller particles occurs as gas flows through the
tubes, where they combine into larger particles, which flow to the
lower section
of
the unit. Further, as the gas stream continues through
the series
of
tubes, a centrifugal force is generated that further removes
any remaining water and small solid particulate matter.
6.1
Water
Removal
Water is a common impurity
in
gas streams, and removal
of
it is nec-
essary to prevent condensation
of
the water and the formation
of
ice
or gas hydrates (C,H,,+,xH,O). Water in the liquid phase causes corro-
sion problems
in
pipelines and equipment, particularly when carbon
dioxide and hydrogen sulfide are present
in
the gas. The simplest
method of water removal (refrigeration or cryogenic separation) is to
cool the gas
to
a temperature at least equal to or (preferentially) below
the dew point (Figure
6-2).
Most of the water associated with natural gas is removed by simple
separation methods at or near the wellhead. However, the removal of
the water vapor that exists in solution in natural gas requires a more
complex treatment. This treatment consists of
dehydrating
the natural
gas, which usually involves one of
two
processes: absorption or
adsorption.
A
dehydration process is needed to eliminate water that may cause
the formation of hydrates. Hydrates form when a gas or liquid con-
taining free water experiences specific temperature/pressure condi-
tions. Dehydration is the removal
of
this water from the produced
138
Chaater
6
Process Classification
Gat
to
Gas
Exchanger
Weak
GIycol
fo
Reconcenfrator
Figure
6-2
The refrigeration process using
glycol
(Geist,
1985).
natural gas and is accomplished by several methods. Among these is
the use
of
ethylene glycol (glycol injection) systems as an absorption
process. The process removes water and other solids from the gas
stream. Alternatively, adsorption dehydration may be used, using dry-
bed dehydrators towers, which contain desiccants such as silica gel
and activated alumina to perform the extraction.
In
most cases, cooling alone is insufficient and, for the most part,
impractical for use in field operations. Other water removal processes
use
(1)
hygroscopic
liquids (e.g., diethylene glycol or triethyiene glycol)
and
(2)
solid adsorbents or desiccants (e.g., alumina, silica gel, and
molecular sieves). Ethylene glycol can be directly injected
into
the gas
stream
in
refrigeration plants.
The glycol has a chemical affinity for water and removes water from
the gas stream.
In
this process, a liquid desiccant dehydrator serves to
absorb water vapor from the gas stream. Essentially, glycol dehydra-
tion involves using a glycol solution, usually either diethylene glycol
(DEG) or triethylene glycol (TEG), which is brought into contact with
the wet gas stream in a
contactor.
The glycol solution absorbs water
from the wet gas and, once absorbed, the glycol particles become
heavier and sink to the bottom
of
the contactor where they are
removed. The natural gas, having been stripped
of
most
of
its water
content,
is
then
transported
out
of
the
dehydrator.
The
glycol
solu-
tion, bearing all
of
the water stripped from the natural
gas,
is put