SESSION 3: GAS PROCESSING USING
ASPENTECH HYSYS
LEARNING OBJECTIVES & GOALS
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The objective of this course module is as follows;
To expose the participants to a typical gas processing facility configuration.
To help participants become conversant with terminologies applied in gas processing
facility.
To help participants become conversant with the different technologies used in gas
processing facilities.
To expose the participants to the use of HYSYS in simulating a typical gas processing
facility.
ABBREVIATIONS & MEANINGS
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GPM: Abbreviation for gallons of recoverable liquid hydrocarbons per thousand cubic
feet of natural gas.
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Light Ends: The low-boiling, easily evaporated components of a hydrocarbon liquid.
HHV: Higher of gross heating value. The quantity known as higher heating value
(HHV) is determined by bringing all the products of combustion back to the original
pre-combustion temperature, and in particular condensing any vapor produced.
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LHV: Lower of net heating value. The quantity known as lower heating value (LHV) is
determined by subtracting the heat of vaporization of the water vapor from the higher
heating value. This treats any H2O formed as a vapor. The energy required to
vaporize the water therefore is not released as heat
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Wet or rich gas: Natural gas containing heavier hydrocarbons. Its liquid content
adds important economic value to developments containing this type of fluid.
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Lean or Dry gas: Natural gas that contains a few or no liquefiable liquid
hydrocarbons
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Natural Gas: Natural gas is a naturally occurring hydrocarbon gas mixture
consisting primarily of methane, but commonly including varying amounts of other
higher alkanes, and sometimes a small percentage of carbon dioxide, nitrogen,
hydrogen sulfide, or helium.
ABBREVIATIONS & MEANINGS
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GOR: Abbreviation for Gas Oil Ratio. The ratio of produced gas to produced oil at
stock tank conditions.
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J-T: This means Joule-Thomson. Referring to the change in temperature observed
when a gas expands while flowing through a restriction without any heat entering or
leaving the system.
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LTS: This means Low temperature Separation or separator. This involves the
separation of heavy liquid hydrocarbons by subjecting them to low temperature.
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FTP: The pressure determined at the formation face during the flowing periods of a
well test.
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API Gravity: American Petroleum Institute gravity is a measure of how heavy or light
a petroleum liquid is compared to water
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Separator: This designates a pressure vessel used for separating well fluids
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produced from oil and gas wells into gaseous and liquid components.
Gas processing facility: Also known as gas plant. This refers to a series of unit
operations put together to separate the heavier hydrocarbons from the lighter ones.
Natural Gas Characterization
Natural Gas is a naturally occurring mixture of hydrocarbon gases that is highly
compressible and expansible. Methane [CH4] is the chief constituent of most natural gas
(constituting as much as 85% of some natural gases), with lesser amounts of ethane
[C2H6], propane [C3H8], butane [C4H10] and pentane [C5H12]. Impurities can also be
present in large proportions, including carbon dioxide, helium, nitrogen and hydrogen
sulfide. It usually exists with crude oil or in some cases exists alone. Natural gas contains
other liquid hydrocarbons such as propanes, butanes, pentanes and heavier products
extracted from the gas flowstream.
The conditioning of natural gas for transportation and sale involves two process
objectives;
1. Separation of the natural gas from free liquids (crude oil, brine, water) and entrained
solids (sand)
2. Removal of impurities from the natural gas and any condensate formed to meet
sales/re-injection specifications while observing all environmental regulations.
Sales specifications can be described most readily in terms of the composition and
properties of the produced hydrocarbons. Also, the selection, design and operation of the
processes required to separate gas from liquid and to remove impurities depend on the
well stream properties. For wet natural gas, the liquid content is given in barrels of
condensate per million standard cubic feet of gas (bbl/MMscf) or in U.S gallons of
condensate per thousand standard cubic feet (GPM).
Well Fluid and Nat. gas constituents
Wells are generally characterized by their fluid type as shown from Table 2-2 below.
Other means of characterizing wells especially through the use of their GOR have been
discredited because the GOR of wells does not actually reflect the condition of the fluid in
the reservoir.
As produced in the field, natural gas may contain the substances shown in Table 2-3. The
primary constituents are usually the paraffinic hydrocarbons (alkanes), methane through
pentane, including both iso-butane and iso pentane. There is apparently very little or no
neo-pentane.
The main constituent of natural gas is methane, desirable as a primary fuel. Sales gas
also contains smaller amounts of the heavier hydrocarbons listed in table 2-3. Often a
portion of the heavier hydrocarbons can be recovered profitably in a field gas processing
plant as one or more liquid products. These liquefiable components ( or condensate) may
be recovered as a single liquid stream that is transported to a separate plant for
fractionation into saleable products. Alternatively, in very large field units, fractionation is
performed in the field.
Well Fluid and Nat. gas constituents
Natural gas Compositions
The gas analyses shown in Table 2-5 span the composition ranges normally
encountered. These analyses are typical of the data furnished to the designer of surface
processing equipment. As earlier mentioned, the heavier hydrocarbons in these gases
are regarded as recoverable liquids. The amount of potentially recoverable liquid is
expressed as gallons liquid at 60oF, if totally condensed, per 1000 standard cubic feet of
the gas (so called GPM, not to be confused with gallons per minute). A gas is termed
lean or rich as follows;
The above classification is based on ethane and heavier hydrocarbons (c2+)
because ethane is sometimes regarded as a desirable feed for petrochemical processes
and can be recovered as a liquid in expander-type gas processing plants. If ethane is not
regarded as a valuable liquid component, the GPM can be based on propane and
heavier hydrocarbons (c3+).
Well Fluid and Nat. gas constituents
Well Fluid and Nat. gas constituents
Natural gas Compositions
The weak link in gas analysis is often the composition of the C6+ or C7+ portion of the
gas. For many purposes, the small amount of the C6+ material renders its
characterization unimportant. One important exception is when a full well stream gas is to
be transported in a pipeline over a long distance, such as from an offshore platform.
Condensation of liquids in the line will cause a large pressure drop that must be
anticipated if adequate platform compression is to be furnished and the proper pipe
diameter selected. Very accurate characterization of the C6+ is needed for this
application so as to predict HC dew points. Accurate characterization of the C7+ fraction
also is needed for prediction of reservoir behavior and for calculating heating values.
Table 2-7 shows some of the nat. gas pipeline specifications.
Natural Gas liquids Recovery
Hydrocarbon condensate recovered from natural gas may be shipped without further
processing or stabilized to produce a safely transportable liquid. In this case of raw
condensate, there are no particular specifications for the product other than the process
requirements. Stabilized liquid, on the other hand, will generally have a vapor-pressure
specification, since the product will be injected into a pipeline or transport pressure vessel
which has definite pressure limitations.
Natural gas liquids are prepared by fractionation of the raw make into appropriate
products, either at the field processing site or, perhaps more commonly, at a large central
facility. In any case, product specifications are not so typical as those of sales gas, but
depend heavily on the particular contract.
The recovery of light hydrocarbon liquids from natural gas streams can range from
simple dew point control to avoid liquid formation to deep ethane extraction. The desired
degree of liquid recovery has a profound effect on process selection, complexity, and cost
of the processing facility.
The term NGL (natural gas liquids ) is a general term which applies to liquids
recovered from natural gas and as such refers to ethane and heavier products. The term
LPG (liquefied petroleum gas) describes hydrocarbon mixtures in which the main
components are propane, iso and normal butane, propene and butenes. Typically in
natural gas production olefins are not present in LPG.
Typically, modern gas processing facilities produce a single ethane plus product
(normally called Y-grade) which is often sent offsite for fractionation and processing.
Whether accomplished on-site or at another facility, the mixed product will typically
be fractionated to make products such as purity ethane, ethane-propane (EP),
commercial propane, isobutane, normal butane, mixed butanes, butane-gasoline (BG),
and gasoline (or stabilized condensate).
LEAN OIL ABSORPTION
The oldest kind of gas plants are absorption/lean oil plants, where a kerosene type oil is
circulated through the plant as shown in Figure 9-1. The "lean oil" is used to absorb light
hydrocarbon components from the gas. The light components are separated from the rich
oil and the lean oil is recycled. Typically the inlet gas is cooled by a heat exchanger with
the outlet gas and a cooler before entering the absorber. The lean absorber oil trickles
down over trays or packing while the gas flows upward countercurrent to the absorber oil.
The gas leaves the top of the absorber while the absorber oil, now rich in light
hydrocarbons from the gas, leaves the bottom of the absorber. The cooler the inlet gas
stream the higher the percentage of hydrocarbons which will be removed by the oil. Rich
oil flows to the rich oil de-ethanizer (or de-methanizer) to reject the methane and ethane
(or the methane alone) as flash gas. In most lean oil plants the ROD unit rejects both
methane and ethane since very little ethane is recovered by the lean oil. If only methane
were rejected in the ROD unit, then it may be necessary to install a de-ethanizer column
downstream of the still to make a separate ethane product and keep ethane from
contaminating (i.e., increasing the vapor pressure of) the other liquid products made by
the plant.
The ROD is similar to a cold feed stabilizing tower for the rich oil. Heat is added at
the bottom to drive off almost all the methane (and most likely ethane) from the bottoms
product by exchanging heat with the hot lean oil coming from the still. A reflux is provided
by a small stream of cold lean oil injected at the top of the ROD. Gas off the tower
overhead is used as plant fuel and/or is compressed. The amount of intermediate
components flashed with this gas can be controlled by adjusting the cold lean oil reflux
rate.
LEAN OIL ABSORPTION
LEAN OIL ABSORPTION
Absorber oil then flows to a still where it is heated to a high enough temperature to drive
the propanes, butanes, pentanes and other natural gas liquid components to the
overhead. The still is similar to a crude oil stabilizer with reflux. The closer the bottom
temperature approaches the boiling temperature of the lean oil the purer the lean oil
which will be re-circulated to the absorber. Temperature control on the condenser keeps
lean oil from being lost with the overhead.
Thus the lean oil, in completing a cycle, goes through a recovery stage where it recovers
light and intermediate components from the gas, a rejection stage where the light ends
are eliminated from the rich oil and a separation stage where the natural gas liquids are
separated from the rich oil.
These plants are not as popular as they once were and are rarely, if ever, constructed
anymore. They are very difficult to operate, and it is difficult to predict their efficiency at
removing liquids from the gas as the lean oil deteriorates with time. Typical liquid
recovery levels are:
C3 = 80%
C4 = 90%
C5+ = 98%
MECHANICAL REFRIGERATION
Often excess pressure is not available to operate an LTS system. An alternative to the
expansion refrigeration system is to utilize a mechanical refrigeration system to remove
heavy hydrocarbon components and reduce the gas dew point. In a refrigeration plant the
inlet gas is cooled to a low enough temperature to condense the desired fraction of LPG
and NGL. Either freon or propane is used as the refrigerant. Figure 9-2 shows a typical
refrigeration plant.
The free water must be separated and the dew point of the gas lowered before cooling
the feed to keep hydrates from forming. It is possible to dehydrate the gas with TEG or
mole sieves to the required dew point. It is more common to lower the hydrate
temperature by injecting glycol in the gas after separation of free water. The glycol and
water separate in the cold separator where they are routed to a regenerator, the water is
boiled off and the glycol is circulated back to be injected into the inlet stream. Some
glycol will be lost with time and will have to be made up. The most common glycol used
for this service is ethylene glycol because of its low cost and the fact that at the low
temperatures it is not lost to the gas phase.
The chiller is usually a kettle type exchanger. Freon (which is cooled in a refrigeration
cycle to -200F) is able to cool the gas to approximately -15 0F. Propane, which can be
cooled to -400F, is sometimes used if lower gas temperatures and greater recovery
efficiencies are desired. The gas and liquid are separated in the cold separator, which is a
three-phase separator. Water and glycol come off the bottom, hydrocarbon liquids are
routed to the distillation tower and gas flows out the top. If it is desirable to recover
ethane, this still is called a de-methanizer. If only propane and heavier components are to
be recovered it is called a de-ethanizer.
MECHANICAL REFRIGERATION
The gas is called "plant residue" and is the outlet gas from the plant. The tower operates
in the same manner as a condensate stabilizer with reflux.
The inlet liquid stream is heated by exchange with the gas to approximately 300oF and is
injected in the tower at about the point in the tower where the temperature is 300oF. By
adjusting the pressure, number of trays, and the amount of reboiler duty, the composition
of the bottoms liquid can be determined.
By decreasing the pressure and increasing the bottoms temperature more methane and
ethane can be boiled off the bottoms liquid and the RVP of the liquid stream decreased to
meet requirements for sales or further processing. Typical liquid recovery levels are:
C3 = 85%
C4 = 94%
C5+ = 98%
These are higher than for a lean oil plant. It is possible to recover a small percentage of
ethane in a refrigeration plant. This is limited by the ability to cool the inlet stream to no
lower than -400oF with normal refrigerants. Most refrigeration plants use freon as the
refrigerant and limit the lowest temperature to -200F. This is because the ANSI piping
codes require special metallurgy considerations below -200F to assure ductility.
MECHANICAL REFRIGERATION
CRYOGENIC PLANTS
Figure 9-3 shows a typical cryogenic plant where the gas is cooled to -100oF to -150oF
by expansion through a turbine or Joule-Thompson (J-T) valve. In this example liquids
are separated from the inlet gas at 100oF and 1,000 psig. It is then dehydrated to less
than 1 ppm water vapor to assure that hydrates will not form at the low temperatures
encountered in the plant. Typically, a mole sieve dehydrator is used.
The gas is routed through heat exchangers where it is cooled by the residue gas, and
condensed liquids are recovered in a cold separator at approximately -900F. These
liquids are injected into the de-methanizer at a level where the temperature is
approximately -900F. The gas is then expanded (its pressure is decreased from inlet
pressure to 225 psig) through an expansion valve or a turbo expander. The turbo
expander uses the energy removed from the gas due to the pressure drop to drive a
compressor, which helps recompress the gas to sales pressure. The cold gas (-1500F)
then enters the de-methanizer column at a pressure and temperature condition where
most of the ethanes-plus are in the liquid state.
The de-methanizer is analogous to a cold feed condensate stabilizer. As the liquid falls
and is heated, the methane is boiled off and the liquid becomes leaner and leaner in
methane. Heat is added to the bottom of the tower using the hot discharge residue gas
from the compressors to assure that the bottom liquids have an acceptable RVP or
methane content. The gas turbine driven compressor is required since there are energy
losses in the system. The energy generated by expanding the gas from 600 psig to 225
psig in the turbo-expander cannot be 100% recovered and used to recompress the
residue gas from 225 psig to 600 psig.
CRYOGENIC PLANTS
In this particular plant it is only capable of recompressing the gas to 400 psig. Thus, even
if the inlet gas and sales gas were at the same pressure, it would be necessary to provide
some energy in the form of a compressor to recompress the gas.
Because of the lower temperatures that are possible, cryogenic plants have the highest
liquid recovery levels of the plants discussed. Typical levels are:
C2 > 60%
C3 > 90%
C4+ = 100%
CHOICE OF PROCESS
Because of the greater liquid recoveries, cryogenic plants are the most common designs
currently being installed. They are simple to operate and easy to package, although
somewhat more expensive than refrigeration plants. Refrigeration plants may be
economical for rich gas streams where it is not desired to recover ethane. Lean oil plants
are expensive and hard to operate. They are rarely designed as new plants anymore.
Existing lean oil plants are sometimes salvaged, refurbished and moved to new locations.
Fractionation
The bottoms liquid from any gas plant may be sold as a mixed product. This is common
for small, isolated plants where there is insufficient local demand. The mixed product is
transported by truck, rail, barge or pipeline to a central location for further processing.
Often it is more economical to separate the liquid into its various components and sell it
as ethane, propane, butane, and natural gasoline. The process of separating the liquids
into these components is called fractionation.
Figure 9-4 shows a typical fractionation system for a refrigeration or lean oil plant. The
liquid is cascaded through a series of distillation towers where successively heavier and
heavier components (fractions) are separated as overhead gas. In this figure the liquid
from the still of an absorption plant or the de-methanizer (or de-ethanizer) tower of an
expansion or refrigeration plant is routed to a de-propanizer. If there is too high a fraction
of butanes-plus in the propane, this can be reduced by adjusting the de-propanizer
pressure upward or reflux condensing temperature downward.
CHOICE OF PROCESS
CHOICE OF PROCESS
If the vapor pressure of the propane exceeds the required specification this means that
the fraction of methane and ethane in the inlet stream is too high. This fraction can be
adjusted downward by increasing the temperature or decreasing the operating pressure
of the still or tower that feeds liquid to the de-propanizer.
The de-butanizer works in a similar manner. The upstream tower (depropanizer)
determines the maximum vapor pressure of the butane product. If the concentration of
propane-minus is too large in the inlet stream, the vapor pressure of the butane
overheads will be too high. Similarly, the concentration of pentanes-plus in the butane will
depend upon the reflux condensing temperature and tower operating pressure. If the
pentanes-plus exceed specifications, further reflux cooling or a higher operating pressure
will be needed to condense pentanes-plus from the butane overheads.
The temperature at the base of the de-butanizer determines the vapor pressure of the
gasoline product. If its vapor pressure is too high, the temperature must be increased or
the tower pressure decreased to drive more butanes-minus out of the bottoms liquids. If
the feed to the fractionator contains recoverable ethane, such as is likely to be the case
with a cryogenic plant, then a de-ethanizer tower would be installed upstream of the depropanizer.
CHOICE OF PROCESS
Quick generalizations regarding selection of a condensate recovery process are difficult.
In some cases an economic comparison between viable alternatives would be required,
however a few guidelines can be offered.
• If the NGL content of the feed gas is low, expander process will probably be the
method of choice. For gases very rich in NGL, simple refrigeration is probably the
best choice, while lean oil absorption are usually not satisfactory.
• If the inlet gas pressure is very high, Low Temperature Separation (LTS) may be
attractive; this process has been used both on and off shore. It is important that the
reservoir pressure remain high for the intended life of the plant. Low inlet gas
pressure favors an expander plant or straight refrigeration (if the gas is rich).
• Very low gas rates may justify only a simple process, such as an automatically
operated J-T unit. Large flow rates justify a more complex plant with more complex
controls and more operating personnel.
Especially if few in number, remote wells may dictate simple operation and processing,
such as LTS. A large number of wells may justify a central proccessing facility with more
complex processing. Offshore locations usually demand simple processing because of
expensive platform area and low weight requirements.
In summary, unique factors affect the process choice for each application. More and
more expander plants are being used due to their low operating cost and simplicity. Such
plants can also be adapted for ethane rejection , making them more versatile and
responsive to product prices.
DEW POINT CONTROL
Retrograde condensation has long been known to occur at reservoir conditions.
Recognition that it also occurs in typical processing conditions was an early result of
computer calculations using equations of state to predict vapor-liquid behavior.
These dew point curves show that as the pressure is reduced, liquid is formed. The
heavier the hydrocarbon, the more the dew point temperature increases as the pressure
is lowered. The cricondentherm of the dew point curve is primarily determined by the
presence of the heaviest component in the gas rather than just the total quantity of the
heavy component in the feed gas. So accurate determination of the heaviest components
is important in establishing the phase envelope.
When gas is transported in pipelines, consideration must be given to the control of the
formation of hydrocarbon liquids in the pipeline system. Condensation of liquid is a
problem in metering, pressure drop and safe operation. Condensation of liquid can also
be a major problem due to two-phase flow and liquid slugging.
To prevent the formation of liquids in the system, it is necessary to control the
hydrocarbon dew point below the pipeline operating conditions. Since the pipeline
operating conditions are usually fixed by design and environmental considerations,
single-phase flow can only be assured by removal of the heavier hydrocarbons from the
gas.
LTS AND LTX
Several methods can be used to reduce the hydrocarbon dew point. If sufficient pressure
is available, the removal can be accomplished by expansion refrigeration in an LTS unit.
The expansion refrigeration system uses the Joule-Thomson effect to
reduce the gas temperature upon adiabatic expansion. This temperature reduction
results in not only hydrocarbon liquid condensation but also water condensation. The
water is generally removed as hydrates in this process, melted and removed.
Thus, the process can actually accomplish dew point control of both water and
hydrocarbon in a single unit.
Fig. 16-3 shows one example of an LTX system. The high pressure gas may first go
through a heater but this is often not needed, depending on the gas conditions. The gas
then enters the heat exchanger coil in the bottom of the separator where the gas is
cooled by exchange with the condensed liquid and by melting the hydrates formed. Any
water or condensate produced at this point is removed in the high pressure separator.
The gas from the separator is then heat exchanged with the outlet product gas for further
cooling. The temperature must be controlled at this point to prevent hydrate formation in
the exchanger.
The gas from this point passes through the pressure reducing valve where the JouleThomson expansion occurs. The hydrocarbon liquid and hydrates produced from this
expansion fall to the bottom of the low temperature separator. The hydrates are melted
and both the water and condensate are removed by level control. The gas leaving the
separator has a hydrocarbon dew point equal to the temperature and pressure of the
separator.
LTS AND LTX PROCESSES
The hydrocarbon and water dew points achievable with this process are limited by the
pressure differential available as well as the composition of the feed gas. The LTS system
can only be used where sufficient pressure is available to perform the desired processing
and separation. It is an attractive process step if sufficient liquid removal can be achieved
at the available operating conditions. A further modification to this process is to add glycol
injection to the high pressure gas to allow the achievement of lower water dew points
when available pressure is limited. Fig. 16-4 shows an LTS system with glycol injection.
The use of the glycol eliminates the need to heat the LTS liquid phase and helps to
ensure that no hydrate formation will block the process equipment upstream of the LTS.
The LTS may not work effectively if the removal of heavy hydrocarbon then changes the
phase envelope so that partial condensation becomes infeasible. This is typical of lean
gas containing small amounts of heavy hydrocarbons.
LTS AND LTX PROCESSES
LTS AND LTX PROCESSES
LOW TEMP. NGL RECOV.
PROCESSES
Dew point control and mechanical
refrigeration systems are intended for applications
where enough liquefiable hydrocarbons must be removed from the gas stream such that
the gas can be transported without liquids formation and/or where some of the heavier
components must be removed in order to meet a maximum heat content specification. In
these cases, the goal is to meet the natural gas stream sales specification, not recovery
of liquids. In cases where the liquefiable hydrocarbons present in a gas stream are more
valuable as a liquid product than as the heating value they contribute to the gas, more
effective methods of liquids recovery are desired.
The lean oil processes described in the last subsection were the original technique used
for this objective, but as already noted, this technology has been superseded by more
cost effective cryogenic expansion process methods, which are covered in the following
sub-sections.
In order to condense and separate more ethane and propane and thus achieve higher
NGL recovery levels than are possible with dew point control or propane-based
refrigeration alone, more gas cooling must be provided, which means cryogenic
temperatures (below –45°C) are required. In order to achieve these temperatures, a
combination of pressure expansion and chilling is used. The two types of cryogenic
expansion processes in use today are:
1. Adiabatic J-T expansion across a control valve
2. Isentropic expansion through a turboexpander
3. Variants of each system above with supplemental mechanical refrigeration
LOW TEMP. NGL RECOV.
PROCESSES
The turbo expander processes
are the most widely used; however, J-T expansion type
processes are sometimes used for lower recovery levels in unattended or remote
locations, and usually for gas flow rates less than 0.566 MSm3/day. Turbo expander type
processes are used for higher ethane and propane recovery levels with larger gas inlet
flow rates where the cost of the additional equipment is easily justified by the value of the
additional liquids recovered. One limitation on the recovery of ethane and heavier
products is the effect of liquids extraction on the heat content of the residue gas. The
presence of inerts in the feed gas may limit the amount of ethane that can be removed
and still meet the minimum heating value specification for the residue gas. Another
consideration is the liquids recovery level that is justifiable for a given gas composition
and plant location. If ethane can be recovered at a good price differential over its value as
a fuel in the residue gas, then the additional compression and complexity of a high
ethane recovery facility may be justified. If there is no local market for ethane, or no way
to transport high vapor pressure product to market, then only propane and heavier
components may have an economic incentive for recovery. The plant may be designed
for initial operation in a propane recovery mode, with future conversion to ethane
recovery if or when the local demand for ethane justifies the expense of additional
compression. Many plants in North America are designed for dual mode operation in
which the operator can select high ethane recovery or ethane rejection, while still
maintaining high propane recovery. These plants can be switched, during normal
operation, as often as necessary between ethane recovery and ethane rejection, in
response to changes in the processing margin. Historically, recovery of propane and
heavier components is almost always justified.
C3+ Vs. C2+NGL Recovery Compared
Ethane is more volatile than the propane and heavier components in a natural gas
stream so generally deeper cooling is required to condense the ethane fraction than is
needed to condense only the propane and heavier components. The temperatures
needed for ethane recovery are thus colder than those needed for propane recovery
regardless of the process design. This means that more compression power is required
for high ethane recovery than for propane recovery only because of the higher pressure
differential required to produce lower temperatures
across the cryogenic sections and/or refrigeration system. The colder operating
temperatures for ethane recovery mean that more of the plant will be constructed of
stainless steel or aluminum than may be needed for a facility which only recovers
propane. Another consequence of the colder temperatures is that the allowable
concentration of CO2 in the feed to avoid CO2 freezing will be less for an ethane
recovery design than for a propane recovery design. As stated previously, many process
designs can operate in either an ethane recovery mode or in an ethane rejection
(propane recovery) mode, as long as the equipment design temperatures are acceptable
for both modes and the compression power is sufficient to support the desired ethane
recovery level. An ethane recovery design will not be as efficient for propane recovery
compared to a propane recovery specific design. It is, however, possible to combine a
very high efficiency ethane recovery design with a very high efficiency propane recovery
design, if this need is identified during the design phase.
C3+ Vs. C2+NGL Recovery Compared
There is always an incentive to minimize the power, emissions, and capital cost for the
facility for a given recovery level of ethane and/or propane.
A simple J-T expansion type process may have very good economic performance for a
given location, flow rate and product price, but it will have low process recovery
efficiency. This technology is therefore normally restricted to relatively small plants.
Typical J-T cryogenic process configurations are described in the next sub-section. A
good understanding of J-T operation will help in understanding the expander plant
designs in the subsequent sub-sections. Turbo expander plants are operated in a J-T
mode before the turbo expander is started up and when the turbo expander is
unavailable.
J-T EXPANSION
The general concept for the Joule-Thomson (J-T) Expansion design is to chill the gas by
expanding the gas across a J-T valve. With appropriate heat exchange and large
pressure differential across the J-T valve, cryogenic temperatures can be achieved
resulting in acceptable extraction efficiencies. The main difference between the J-T
design and turbo expander is that the gas expansion is adiabatic across the valve and is
nearly isentropic across the turbo expander. The outlet temperature is colder for a given
pressure ratio for the turbo expander than for a J-T valve. The result is that the J-T
design will have much lower ethane or propane recovery for a given amount of residue
compression power than the turbo expander process, but the process is very simple,
which helps make it suitable for some applications.
Specifically, the J-T process is used for situations where the higher efficiency due to the
lower temperatures generated and the work recovered via the turbo expander driven
compressor do not offset the increased cost & complexity involved, such as:
1. The feed gas rate is low and/or,
2. There is a relatively low ethane and propane recovery requirement
3. The unit will be located in a remote or unattended location
4. Where a broad range of inlet gas flow rates and compositions can be expected.
Typical Process Flow for J-T Process
Fig. 16-15 illustrates a typical process flow arrangement for a J-T expansion process. In
order to effectively use the J-T process, the gas must be at a high inlet pressure.
Pressures over 6900 kPa (abs) are typical in these facilities. If the gas pressure is too
low, inlet compression is necessary or sufficient expansion chilling will not be attained.
The gas must first be dried to ensure that no water enters the cold portion of the process.
Typically, molecular sieves or alumina are used for the drying.
Methanol injection has been used in a few plants successfully but can be an operating
problem because the dew point is too close to normal operating temperatures. After
drying, the gas is cooled by heat exchange with the cold residue gas and also by heat
exchange with the demethanizer mid-tower liquids and in some cases the liquids from the
cold separator. After chilling, the gas is expanded across the J-T valve and sent to the
cold separator . The liquid from this separator is the feed to the demethanizer. This
demethanizer column is needed because the separator liquids contain too much methane
and ethane to meet a liquid product specification for downstream fractionation. Usually
this tower is a cold, top feed design. The cold liquid is demethanized to the proper
specification in this tower. The cold overhead product from the demethanizer is used to
cool the feed and is then recompressed as necessary for residue sales. When operated
in an ethane recovery mode, enough heat is provided to the bottom reboiler to limit the
methane content to an acceptable level. When operated in an ethane rejection mode, the
bottom reboiler heat input is adjusted to achieve an acceptable ethane content
specification and the ethane is sent overhead and on to the residue gas sales point.
Typical Process Flow for J-T Process
The liquids recovery for this process is determined by the pressure ratio across the J-T
valve and the quantity of heat exchange surface included in the plant heat exchangers. In
some cases the feed gas is not at high enough pressure or the gas is rich in liquefiable
hydrocarbons. Mechanical refrigeration can be added to the J-T process to increase
recovery of ethane and propane without adding a turbo expander. The gas in this design
is expanded downstream of the cold separator, taking advantage of the cooling provided
by the refrigeration system and feeding the rich liquids separated at high pressure lower
in the column. (The optimum location for the J-T valve is dependent on the inlet gas
pressure and composition.) The advantage of external refrigeration is that lower feed
pressure can be used or,
alternatively, the de-methanizer can be operated at a higher pressure thus reducing
residue compression. For rich gas streams, using external refrigeration is more effective
than increasing inlet or residue compression. The total compression power requirement
(refrigeration plus residue plus inlet) may be minimized with the use of a refrigeration
system although complexity is increased. The optimum combination of compression
power versus recovery level must be determined by process simulation of multiple
equipment arrangements. The J-T process, whether refrigerated or non-refrigerated,
offers a simple, flexible process for relatively low ethane and propane recovery levels
where a turbo expander is not justified.
However, modern turbo expanders have proven to be so beneficial and reliable that
almost all cryogenic plants are designed around turbo expander processes.
Typical Process Flow for J-T Process
TURBO EXPANDER PROCESSES
The modern turbo expander based cryogenic gas plant was commercialized in the mid1960s. Since then almost all new high pressure NGL recovery plants built have employed
a variant of this basic process. Turbo expander process designs use the feed gas
pressure to produce needed refrigeration by expansion across a turbine (turbo
expander). The turbo expander recovers useful work from this gas expansion. Typically
the expander is linked to a centrifugal compressor to recompress the residue gas from
the process. Because the expansion is near isentropic, the turbo expander lowers the
gas temperature significantly more than expansion across a J-T valve. This extraction of
energy from the inlet gas using a turbo expander and its application to the booster
compressor is why the inlet gas stream can be cooled more for a given residue
compressor power level than in a J-T process. More cooling means more condensation
of the desired products so higher product recovery can be achieved for a given residue
compressor size and power level.