lecture 3.pptx

Sweetening Process,
Mooring System and
Hydrocarbon Recovery
Dr Sourav Poddar
Department of Chemical Engineering
National Institute of Technology, Warangal

Products Produced by Refineries

What is Sweetening ?
• Sweetening process means treating process.
• Its means by which contaminants such as organic compounds containing sulfur,
nitrogen, and oxygen, dissolved metals and inorganic salts, soluble salts and water are
removed from petroleum fractions or streams.
• Petroleum refiners have a choice of several different treating processes, but the primary
purpose of the majority of them is the elimination of unwanted sulfur compounds.
• A variety of intermediate and finished products, including middle distillates, gasoline,
kerosene, jet fuel, and sour gases are dried and sweetened.
• Sweetening is a major refinery treatment of gasoline, treats sulfur compounds,
1.Hydrogen sulfide,
2.Thiophene
3.Mercaptan
• It is to improve color, odor, and oxidation stability.
• Sweetening also reduces concentrations of carbon dioxide.

When sweetening process is carried out.
 Treating can be accomplished at an intermediate stage in the refining
process, or just before sending the finished product to storage.
 Choices of a treating method depend on the nature of the petroleum fractions, amount and type
of impurities in the fractions to be treated, the extent to which the process removes the
impurities, and end-product specifications.
 Treating materials include acids, solvents, alkalis, oxidizing, and adsorption
agents.

Sulfuric Acid in Sweetening Process
• Sulfuric acid is the most commonly used acid treating
process.
• Sulfuric acid treating results in partial or complete removal
of unsaturated hydrocarbons, sulfur, nitrogen, and oxygen
compounds, and resinous and asphaltic compounds.
• It is used to improve the odor, color, stability, carbon
residue, and other properties of the oil.

Clay treating
• Clay or lime treatment of acid-refined oil removes traces of
asphaltic materials and other compounds improving
product color, odor, and stability.

Caustic Treating
• Caustic treating with sodium (or potassium) hydroxide is
used to improve odor and color by removing organic acids
(naphthenic acids, phenols) and sulfur compounds
(mercaptans, H2S) by a caustic wash.
• By combining caustic soda solution with various solubility
promoters (e.g., methyl alcohol and cresols), up to 99% of
all mercaptans as well as oxygen and nitrogen compounds
can be dissolved from petroleum fractions.

Drying and Sweetening
 Feedstock from various refinery units are sent to gas treating plants where butanes
and butenes are removed for use as alkylation feedstock, heavier components are
sent to gasoline blending, propane is recovered for LPG, and propylene is
removed for use in petrochemicals.
 Some mercaptans are removed by water-soluble chemicals. Caustic liquid (sodium
hydroxide), amine compounds (diethanolamine) or fixed-bed catalyst sweetening
also may be used.
 Drying is accomplished by the use of water absorption or adsorption agents to remove
water from the products.
 Some processes simultaneously dry and sweeten by adsorption on molecular
sieves.

Typical process equipment for sweetening sour
gas with a regenerative solvent.

 The first vessel is the inlet separator, which performs the important function of separating
the fluid phases on the basis of density difference between the liquid and the gas.
 The sour gas flows from the separator into the lower part of the absorber or contactor. This
vessel usually contains 20 to 24 trays, but for small units, it could be a column containing
packing.
 Lean solution containing the sweetening solvent in water is pumped into the absorber near
the top.
 As the solution flows down from tray to tray, it is in intimate contact with the sour gas as
the gas flows upward through the liquid on each tray.
 When the gas reaches the top of the vessel, virtually all the H2S and, depending on the
solvent used, all the CO2 have been removed from the gas stream.
 The gas is now sweet and meets the specifications for:
1. H2S
2. CO2
3. total sulfur content

• The rich solution leaves the contactor at the bottom and is flowed through a
pressure letdown valve, allowing the pressure to drop to about 60 psig. In some
major gas plants, the pressure reduction is accomplished through turbines
recovering power.
• Upon reduction of the pressure, the rich solution is flowed into a flash drum,
where most dissolved hydrocarbon gas and some acid gas flash off. The
solution then flows through a heat exchanger, picking up heat from the hot,
regenerated lean solution stream.
• The rich solution then flows into the still, where the regeneration of the solvent
occurs at a pressure of about 12 to 15 psig and at the solution boiling
temperature. Heat is applied from an external source, such as a steam reboiler.
The liberated acid gas and any hydrocarbon gas not flashed off in the flash
drum leave the still at the top, together with some solvent and a lot of water
vapor.

 This stream of vapors is flowed through a condenser, usually an aerial cooler, to
condense the solvent and water vapors. The liquid and gas mixture is flowed into
a separator, normally referred to as a reflux drum, where the acid gas is separated
from the condensed liquids.
 The liquids are pumped back into the top of the still as reflux. The gas stream,
consisting mainly of H2S and CO2, is generally piped to a sulfur recovery unit.
The regenerated solution is flowed from the reboiler or the bottom of the still
through the rich/lean solution heat exchanger to a surge tank. From here, the
solution is pumped through a cooler to adjust the temperature to the appropriate
treating temperature in the absorber.
 The stream is then pumped with a high-pressure pump back into the top of the
absorber, to continue the sweetening of the sour gas.

Most solvent systems have a means of filtering the
solution. This is accomplished by flowing a portion of the
lean solution through a particle filter and sometimes a
carbon filter as well. The purpose is to maintain a high
degree of solution cleanliness to avoid solution foaming.
Some solvent systems also have a means of removing
degradation products that involves maintaining an
additional reboiler for this purpose in the regeneration
equipment hook-up. In some designs, the rich solution is
filtered after it leaves the surge drum.

Sweetening solvents
 The desirable characteristics of a sweetening solvent are:
1. Required removal of H2S and other sulfur compounds must be achieved.
2. Pickup of hydrocarbons must be low.
3. Solvent vapor pressure must be low to minimize solvent losses.
4. Reactions between solvent and acid gases must be reversible to prevent solvent
degradation.
5. Solvent must be thermally stable.
6. Removal of degradation products must be simple.
7. The acid gas pickup per unit of solvent circulated must be high.
8. Heat requirement for solvent regeneration or stripping must be low.
9. The solvent should be noncorrosive.
10. The solvent should not foam in the contactor or still.
11. Selective removal of acid gases is desirable.
12. The solvent should be cheap and readily available.

 Unfortunately, there is no one solvent that has all the desirable characteristics. This makes it necessary to
select the solvent that is best suited for treating the particular sour gas mixture from the various solvents that
are available.
 The sour natural gas mixtures vary in:
1. H2S and CO2 content and ratio
2. content of heavy or aromatic compounds
3. content of COS, CS2, and mercaptans
 While most of the sour gas is sweetened with regenerative solvents, for slightly sour gas, it may be more
economical to use scavenger solvents or solid agents. In such processes, the compound reacts chemically
with the H2S and is consumed in the sweetening process, requiring the sweetening agent to be periodically
replaced.

Safety Considerations
 Sweetening processes use air or oxygen.
 If excess oxygen enters these processes, it is possible for a fire to
occur in the settler due to the generation of static electricity, which
acts as the ignition source.
 There is a potential for exposure to hydrogen sulfide, caustic
(sodium hydroxide), spent caustic, spent catalyst (Merox), catalyst
dust and sweetening agents (sodium carbonate and sodium
bicarbonate).

20
Introduction
Mooring System:
The mooring system consists of freely hanging lines
connecting the surface platform to anchors, or piles, on
the seabed, positioned at some distance from the platform.
“Often laid out symmetrically in plan view around the
object in question”

21
Types of Mooring Lines:
1. Steel-Linked chain
2. Wire rope
3. Synthetic fiber rope

22
1. Steel-Linked chain
2. Wire rope
The above two types of catenary lines are conventionally used
for mooring floating platforms.
Each of the lines forms a catenary shape, depending on an
increase or decrease in line tension as it lifts off or settles on
the seabed, to produce a restoring force as the surface
platform is displaced by the environment.
Thus a spread of lines generates a nonlinear restoring force to
provide the station-keeping function.

23
This force increases with vessel horizontal offset and balances
quasi-steady environmental loads on the surface platform.
The equivalent restoring stiffness provided by the mooring is
generally too small to influence wave frequency motions of
the vessel significantly, although excitation by low-frequency
drift forces can induce dynamic magnification in the platform
horizontal motions and lead to high peak line tensions.
The longitudinal and transverse motions of the mooring lines
themselves can also influence the vessel response through
line dynamics.

24
3. Synthetic rope
To operate in more water depths, the suspended weight of mooring lines
becomes a prohibitive factor. In particular, steel chains become less
attractive at great water depths.
Recently, advances in taut synthetic fibre rope technology have been
achieved offering alternatives for deep-water mooring.
Mooring systems using taut fibre ropes have been designed and installed
to reduce mooring line length, mean- and low-frequency platform
offsets, fairlead tension and thus the total mooring cost. (Still a lot of
R&D in progress)

25
Mooring system design philosophy:
Mooring system design is a trade-off between making the system
compliant enough to avoid excessive forces on the platform, and
making it stiff enough to avoid difficulties, such as damage to
drilling or production risers, caused by excessive offsets.
Easier to achieve for moderate water depths, but becomes more
difficult as the water depth increases.

26
Single Point Mooring (SPM):
Excessive offsets are often observed due to the environmental
factors on the mooring system.
SPM have been developed to overcome this disadvantage.
In this the lines are attached to the vessel at a single point.
This connection point is located on the longitudinal centre line of
the vessel.
The vessel is then free to weathervane and hence reduce
environmental loading caused by wind, current and waves.

27
Single Buoy Mooring (SBM):
A typical early facility consisted of a buoy that serves as a mooring
terminal. It is attached to the sea floor either by catenary lines, taut
mooring lines or a rigid column.
The vessel is moored to the buoy either by synthetic hawsers or by
a rigid A-frame yoke.
Turntable and fluid swivels on the buoy allow the vessel to
weathervane, reducing the mooring loads.

28
In order to further reduce the environmental loading on the
mooring system from the surface vessel in extreme conditions, dis-
connectable turret mooring systems have also been developed.
Here the connected system is designed to withstand a less harsh
ocean environment, and to be disconnected whenever the sea state
becomes too severe such as in typhoon areas.

29
Figure: Turret moorings
a) Dis-connectable b) Permanent

30
Functional requirements for the mooring system:
1. Offset limitations
2. Lifetime before replacement
3. Install-ability
4. Positioning ability
These requirements are determined by the function of the
floater.

31
Comparison of typical MODU and FPS mooring requirements:
MODU Floating Production
Design for 50-yr return period event.
Anchors may fail in larger events.
Designed for 100 yr return period
events.
Risers disconnected in storms Risers remain connected in storm
Slack moorings in storm events to
reduce line tensions
Moorings are usually not slacked
because of risk to the risers, and lack
of marine operators on board
Components designed for < 10 yr life Components designed for > 10 yr life
Fatigue analysis not required Fatigue analysis required
Life dynamics analysis not required Life dynamics analysis required
Missing line load case not required Missing line load case required

32
Steel Chain or Wire Catenary lines:
In the figure: Catenary
mooring is deployed from
point A on the submerged
hull of a floating vessel to
an anchor at B on the
seabed.
Some part between AB is
resting on the seabed, &
horizontal distance “a” is 5-
20 times larger than the
vertical dimension “b”.

33
As we shift the mounting point from A1to A4 the catenary line
laying/resting varies from a significant length at A1 to none at A4.
From a static point of view, the cable tension in the vicinity of
point A is due to the total weight in sea water of the suspended
line length.
The progressive effect of line lift-off from the seabed
due to the horizontal vessel movement from Al to A4 increases
line tension in the vicinity of point A.
This feature, coupled with the simultaneous decrease in line angle
to the horizontal, causes the horizontal restoring force on the vessel
to increase with vessel offset in a non-linear manner.

34
For deep-water applications, synthetic fibre lines can
have significant advantages over a catenary chain or wire
because they are considerably lighter, very flexible and
can absorb imposed dynamic motions through extension
without causing an excessive dynamic tension.
Synthetic Lines:

35
This, causes reduced mean- and
low-frequency platform offsets,
lower line tensions at the fairlead and smaller vertical load on the
vessel. This reduction in vertical load can be important as it effectively
increases the vessel useful payload.
Additional advantages include the
fact that there is reduced line
length and seabed footprint, as
depicted in the adjacent figure

36
The disadvantages in using synthetics are that their material
and mechanical properties are more complex and not as well
understood as the traditional rope.
This leads to over conservative designs that strip them of
some of their advantages. Furthermore, there is little in-
service experience of these lines.
In marine applications this has led to synthetic ropes subject
to dynamic loads being designed with very large factors of
safety.

37
Important properties of synthetic lines to considered in design:
 Stiffness
 Hysteresis and heat build up
 Fatigue
 Other issues

38
Stiffness:
In a taut mooring system the restoring forces in surge, sway and
heave are derived primarily from the line stretch.
This mechanism of developing restoring forces mostly differs from
the conventional steel catenary systems that develop restoring forces
primarily through changes in the line catenary shape. This is made
possible by the much lower modulus of elasticity of polyester
compared to steel.
The stretch characteristics of fibre ropes can extend from 1.2 to 20
times as much as steel, reducing induced wave and drift frequency
forces. (Stiffness of line is a function of load & age)

39
Hysteresis and heat build up:
The energy induced by cyclic loading is dissipated (hysteresis) in the
form of heat. In addition, the chaffing of rope components against
each other also produces heat.
Cases are known in which the rope has become so hot that the
polyester fibers have melted. This effect is of greater concern with
larger diameters or with certain lay types because dissipation of the
heat to the environment becomes more difficult.

40
Fatigue:
The fatigue behavior of a rope at its termination is not good. In a
termination, the rope is twisted (spliced) or compressed in the radial
direction (barrel and spike or resin socket).
The main reason for this decreased fatigue life is local axial
compression. Although the rope as a whole is under tension, some
components may go into compression, resulting in buckling and
damage of the fibres.
In a slack line this mechanism is more likely to be a problem than in
a rope under tension. The phenomenon can appear at any position
along the rope.

41
Other relevant issues:
Issues to consider are that the strength of a polyester rope is about
half that of a steel wire rope of equal diameter.
Additionally the creep behavior is good but not negligible (about
1.5% elongation over 20 years). Furthermore, synthetic fibre ropes
are sensitive to cutting by sharp objects and there have been reports
of damage by fish bite. A number of rope types such as high
modulus polyethylene (HMPE) are buoyant in sea water; other types
weigh up to 10% of a steel wire rope of equal strength.
Synthetic fibre lines used within taut moorings require the use of
anchors that are designed to allow uplift at the seabed.

42
Loading Mechanism on Mooring System:
Figure: Environmental forces acting on a moored vessel in head conditions and
transverse motion of catenary mooring lines

43
Loading Mechanism on Mooring System:
There are various loading mechanisms acting on a moored floating
vessel as depicted in the previous figure are:
For a specific weather condition, the excitation forces caused by
current are usually assumed temporally constant, with spatial
variation depending on the current profile and direction with depth.
Wind loading is often taken as constant, at least, in initial design
calculations, though gusting can produce slowly varying responses.
Wave forces result in time-varying vessel motions in the 6 rigid body
degrees of freedom of surge, sway, heave, roll, pitch and yaw.
Wind gust forces can contribute to some of these motions as well.

44
Mooring System Design
 Static design
 Quasi Static Design
 Dynamic Design

45
Mooring Hardware Components
The principle components of a mooring system may consists of:
 Chain, wire or rope or their combination
 Anchors or piles
 Fairleads, bending shoes or pad-eyes
 Winches, chain jacks or windlasses
 Power supplies
 Rigging (e.g. stoppers, blocks, shackles)

46
Chain, wire or rope or their combination:
Properties are given by “Det Norske Veritas OS-E301” codes.
Chain and wire make up the strength members for the mooring system.
There are primary 2 chain constructions:
a) Stud-Link Chain (studs provide stability to the link and
facilitate laying down of chain while handling.)
b) Stud-less Chain (removing stud reduces the weight per unit of
strength and increases the chain fatigue life, at the expense of
making the chain less convenient to handle.)

47
Chain is specified as nominal diameter of the link “D”
The largest mooring chain manufactured to date is the 6.25 in. (159 mm)
Stud-less chain for the Schiehallion FPSO in the North Atlantic (West of Shetlands).

48
Wire rope:
Wire rope consists of individual wires wound in a helical pattern
to form a “strand”.
The pitch of the helix determines the flexibility and axial stiffness
of the strand.
Wire rope used for mooring can be multi-strand or single-strand
construction.
Stud-link chain and six-strand wire rope are the most common
mooring components for MODUS and other “temporary” moorings.

49
Wire rope:
Multi-strand ropes are favored for temporary applications because of
their ease of handling.
Six-strand rope is the most common type of multi-strand rope used offshore.
Mooring line ropes typically consist of 12, 24, 37 or more wires
per strand.
The wires have staggered sizes to achieve higher strength

50
Wire rope:
Figure: Wire rope construction

51
Common “classes” of multi-strand rope include (Myers, 1969):
6x7 class: 7 wires per strand, usually used for standing rigging.
Poor flexibility and fatigue life, excellent abrasion resistance.
Minimum drum diameter/rope diameter (D/d) = 42.
6x9 Class: 16 to 27 wires per strand. Good flexibility and fatigue
life and abrasion resistance. Common in lifting and dredging.
Minimum D/d = 26-33.
6x37 Class: 27 to 49 wires per strand. Excellent fatigue life and
flexibility, but poor abrasion resistance. Minimum D/d = 16-26.

52
Multi-strand wire ropes may contain either a fibre or a metallic core.
The core is important for support of the outer wires, especially on a
drum, and in some applications to absorb shock loading.
Fibre core (FC) ropes are not generally used for heavy duty marine
applications.
Metallic core ropes may be one of the two types:
a) Independent Wire Rope Core (IWRC)
b) Wire-Strand Core (WSC).
IWRC is the most common core filling for heavy marine applications.

53
Anchors or piles:
Anchors are basically of two types, relying either on self-weight or
suction forces.
The traditional embedment anchors, as shown in figure, are not
normally designed for vertical force components. Holding power is
related to anchor weight and type of seabed.

55
Figure: Suction anchor installation sequence

56
Figure: Deep water FPSO design using suction anchors

57
Turrets:
The design of mono-hull turret structures used for single-point
moorings in floating production systems must allow for large static
and dynamic loading caused by the vessel motions in waves together
with forces transmitted by the mooring system.
The hull design in the turret region must reflect the fact that the
amount of primary steel is reduced here with an appropriate increase
in the stress concentration.

58
Careful selection of turret position is important because of its
influence on:
 Mooring line tension and riser loading.
 Vessel yaw
 Rigid body oscillation in the horizontal plane

59
Mooring System Analysis:
The mooring system is assessed in terms of three limit states based
on the following criteria:
 Ensuring that individual mooring lines have suitable strength
when subjected to forces caused by extreme environmental loads -
ultimate limit state (ULS).
 Ensuring that the mooring system has suitable reserve capacity
when one mooring line or one thruster has failed - accidental limit
state (ALS).
 Ensuring that each mooring line has suitable reserve capacity
when subject to cyclic loading - fatigue limit state (FLS).

60
Potential failure modes as given in standards:
 Hysteresis heating:lubricants and fillers can be included to reduce
hotspots, creep rupture - in particular this is relevant to HMPE yarns,
and the risks need careful evaluation.
 Tension: Tension fatigue-only limited data exist, indications being
that fatigue resistance is higher than for steel wire ropes.
 Axial compression fatigue - on leeward lines during storms for
example, prevented by maintaining a minimum tension on the rope.
 Particle ingress - causes strength loss by abrasion from water-
borne material such as sand, prevented by using a suitable sheath
and not allowing contact between the rope and seabed.
Reference: S. K. Chakrabarti / “Handbook of Offshore Engineering” Vol- 1 & 2 / Elsevier-05

RETROGRADE CONDENSATION
A major reason for dew point control is the fact that rich natural gas mixtures that contain
heavier hydrocarbons exhibit a nonintuitive behavior called retrograde condensation.
Figure – 1: Pressure−temperature diagram
for a hypothetical raw natural gas that
contains predominately methane, with
trace components up to heptane. The
dashed curve represents the vapor-phase
line at 95% quality. Points A, B, and C
denote the cricondentherm, cricondenbar,
and critical point of the mixture,
respectively.

Three points on the envelope are important:
• The cricondentherm, the maximum temperature at which two phases can exist
• The cricondenbar, the maximum pressure at which two phases can exist
• The critical point, the temperature and pressure where the liquid and vapor phases have the same concentration
The retrograde condensation effect can be seen by following the vertical dashed line in Figure – 1. For the mixture at
the temperature and pressure at the top of the line, a single phase exists. Dropping the pressure causes a
liquid phase to form (retrograde condensation), which will be present until the pressure is below the
envelope. The dotted-line path is similar to what happens in a pipeline because of line pressure drop if
pipeline temperature is constant.
The dashed curve inside the envelope denotes the pressure and temperature of the mixture when the vapor
quality is 95 mol%. This curve shows the dramatic effect on the phase behavior from condensation of only 5 mol%
of the vapor. The cricondentherm of this vapor phase is about 50°F (30°C) lower than the original mixture, and
condensation at typical pipeline temperatures would not be possible.
As can be seen from the previous paragraph, the cricondentherm of a mixture strongly depends on the
molecular weight of the heavy components. The cricondenbar increases with increased molecular weight.
Concentration of the heavy components present is relatively less important than their molecular weight. On
the basis of simple flash calculations, a mixture that contains methane and 10 mol% propane has a
cricondentherm comparable to a methane–heptane mixture with only 0.06 mol% heptane.

Basic Propane Refrigeration Process
FIGURE 2 Schematic of refrigeration cycle on a pressure−enthalpy chart
• refrigeration cycle consists of four steps that are depicted on
the pressure−enthalpy chart
1. Compression of saturated refrigerant vapor at
point A to a pressure well above its vapor
pressure at ambient temperature at point B
2. Condensation to point C by heat exchange with
a cooling fluid, usually air
3. Expansion through a valve (Joule-Thomson
expansion) to cool and condense the refrigerant
to point D
4. Heat exchange with the fluid to be cooled by
evaporation of the refrigerant back to point A

Single-stage propane refrigeration system.
(Adapted from Engineering Data Book, 2004d.)
1. Compression Step—
2. Condensation Step—
3. Expansion Step—
4. Refrigeration Step—

1. Compression Step—
Cycle analysis begins with propane vapor entering the compressor as a vapor at 14.5 psia (1 bar) and approximately
−40°F (−40°C), where it is compressed to 250 psia (17 bar). The power required and compressor discharge temperature
depends upon compressor efficiency. Plants once used multistaged reciprocating compressors, but oil-injected
screw compressors are now preferred because they can complete the compression in one stage. (Large
refrigeration units such as those used in LNG plants use centrifugal compressors.)
The work of compression is simply
(1)
where 𝜂𝐵 is the adiabatic efficiency of the compressor. Taking into account compressor nonideality, the actual enthalpy
at the end of the expansion is
(2)
Compressor power to the refrigeration system is the product of the mass flow rate and shaft work
(3)

2. Condensation Step—
The warm gas goes to an air- or water-cooled condenser, where the propane cools to 100 to 120°F (38 to 50°C),
totally condenses, and collects in a receiver. This step is simply
(4)
3. Expansion Step—
Propane liquid leaves the receiver and flashes through a J-T valve, where the temperature and pressure drop to −40°F
(−40°C) and 16 psia (1 bar) (point C to point D). No change occurs in the enthalpy, but the temperature drops to the
saturation temperature of the liquid at the expansion-discharge pressure, and hC = hD if there are no heat leaks. If there
is a heat leak, qL, then
(5)
The fraction, f, of propane condensed is computed knowing the initial enthalpy and liquid and vapor enthalpies at the
condensation temperature, which for the given case is
Assuming the vapor leaves the chiller as a saturated vapor,
(6)

4. Refrigeration Step—
The cold propane then goes to a heat exchanger, the chiller, where it cools the process stream by evaporation (point D to
point A in Figure 2).
Because the propane in the chiller is evaporating, and a minimal heat exchange occurs between cold propane vapor and
the inlet gas, the inlet and outlet propane temperature remains constant. The propane returns to the compressor suction
slightly above −40ºF (−40°C). The heat absorbed by the propane is simply hA − hD.
Refrigeration-cycle performance is commonly stated in terms of coefficient of performance (COP), which is the ratio of
the refrigeration obtained divided by the work required. On the basis of Figure 2, the COP is determined by
(7)

Example-1 Compute the liquid fraction produced and the COP
for the propane refrigeration system on the basis of the
conditions given in Figure 3. Ignore heat leak into the
system and assume the compressor efficiency is 77%.
Use the saturation table and PH diagram for propane
given in below for the calculations.

Pressure-enthalpy
diagram for propane
in engineering units
(ASHRAE, 2005).

Compression Step—
Following the cycle as given above, first calculate the work of compression. To compute compressor work, we use
Equation
and assume that the inlet-gas condition is saturated vapor at –40°F. The work per unit mass (assuming reversible
compression) required to compress the propane from 14.5 to 250 psia (from Table and Figure above) is

Condensation Step—
Pressure drop between the condenser inlet and receiver is usually around 8 to 10 psi (0.55 to 0.7 bar). The heat
load on the condenser is the change in enthalpy from the heated vapor to condense to all liquid. On the basis of
the saturation table, this value is
To calculate the mass fraction condensed use Equation 6
The COP is, from Equation 7:

Alternate Process Configurations
Two-stage propane refrigeration system, with second heat exchanger and economizer. Units may omit either the first stage
heat exchanger or expansion directly to the economizer.

Effect of Multistaging on Condenser and Compression Duty for Constant Refrigeration Duty with Propane as the
Refrigerant

HEAT EXCHANGE
• Plate-Fin Exchangers • Printed Circuit Heat Exchangers
Advantages of plate-fin exchangers include
• Light weight.
• Excellent mechanical strength at subambient temperatures (used in liquid helium service [−452ºF (−268ºC)]). Can
operate at pressures up to 1,400 psig (96 barg).
• High heat transfer surface area. Up to six times the surface area per unit volume of shell and tube exchanger and
25 times the area per unit mass.
• Complex flow configurations. Can handle more then 10 inlet streams with countercurrent, crossflow, and
counter crossflow configurations.
• Close temperature approaches. Temperatures of 3F (1.7C) for single phase fluids compared with 10 to
15ºF (6 to 9ºC) for shell and tube exchangers and 5F (2.8C) for two-phase systems.
• Plate-Fin Exchangers

• Plate-Fin Exchangers
• Single-unit construction. Repair can be more costly and time consuming than with shell and tube exchangers.
• Maximum operating temperature of approximately 150°F (~85°C), although special designs go to 400°F (205°C).
• Narrow channels. More susceptible to plugging, and fine mesh screens are needed where solids may enter. Components
that might freeze out, water, CO2, benzene, and p-xylene, must be in sufficiently low concentrations
to avoid plugging. The exchangers can be difficult to clean if plugging occurs.
• Less rugged. Does not accept rough handling or high pipe stress on nozzles.
• Limited to fluids noncorrosive to aluminum. Caustic chemicals are corrosive but not corroded by acid gases, unless free
water is present.
• Susceptible to mercury contamination. Mercury amalgamates with aluminum to destroy mechanical strength.
• Susceptible to thermal shock. Maximum rate of temperature change is 4°F/min (2°C/min ), and maximum difference
between two streams is 55°F (30°C) (Howard, 1998).
Drawbacks and limitations of the exchangers include:

• Printed Circuit Heat Exchangers
The printed circuit heat exchanger (PCHE) is used in clean service. This technology is
relatively new, commercialized in the 1980s, but hundreds of units are in service
(Pua and Rumbold, 2003). Like electronic printed circuits, heat transfer
passages are etched in plates, and the plates are bonded together by diffusion
bonding. Unlike the brazed-aluminum exchangers, they are rugged and,
depending on materials of construction, go to high temperatures and pressures
but can still handle complex flow schemes that involve many streams. Heat
transfer passage sizes range from “microchannels” (less than 8 mil, 200
microns) to “minichannels” (0.12 in, 3 mm) to provide high heat transfer surface
areas. Heat transfer area per unit volume can be 800 compared with 500 for
plate-fin exchangers. Like plate-fin exchangers, vendor design is required.

FRACTIONATION
In addition to conventional distillation columns, two other types of distillation columns are commonly found in gas
plants: stabilizers and demethanizers.
Stabilizers
The primary focus of dew pointing or fuel conditioning is to obtain a leaner gas. However, the “by-product” is a
liquid phase that contains a substantial amount of volatiles. To make the liquid product easier to store and to recover
more light ends for fuel or sales gas, many of the systems will “stabilize” the liquid by passing it through a stabilizer
column. The stabilizer feed typically enters at the top of a packed or tray column and no reflux occurs. To increase
stripping of light ends, the column pressure will be lower than that of the gas separator that feeds the column. In
some cases, a stripping gas may be added near the bottom of the column in addition to the externally heated
reboiler installed to provide additional vapor flow and enhance light-ends removal. This feature usually comes as an
increased operating cost because the gas from the stripper is at low pressure and must be recompressed if put back
into the inlet gas stream upstream of the gas treating unit.

Demethanizer
The column differs from usual distillation columns in the following ways:
• It has an increased diameter at the top to accommodate the predominately vapor feed to the top tray.
• It is typically primarily a stripping column, with no traditional condenser–reflux stream.
• It may have several liquid feed inlets further down the column that come from low-temperature
separators.
• It may have several side reboilers, the primary purpose of which is to cool the gas going
through the reboiler to recover some of the refrigeration available in the warming NGL stream.
• It has a large temperature gradient; over 170F (75C) is common.

RECOVERY PROCESSES
The following three sections include the three hydrocarbon-recovery systems:
1. Dew point control and fuel conditioning
2. Low ethane recovery
3. High ethane recovery
DEW POINT CONTROL AND FUEL CONDITIONING
Dew point control and fuel conditioning exist to knock out heavy hydrocarbons from the gas stream. These
operations are primarily field operations.

Low Temperature Separators
Low-temperature separator (LTS), with glycol injection and condensate stabilization.

Twister
Advantages of the system include:
• Simplicity. No moving parts and no utilities required.
• Small size and low weight. A 1-inch (24-mm) throat diameter, 6 feet (2 m) long tube can process 35 MMscfd (1
MMSm3/d) at 1,450 psia (100 bar).
• Driven by pressure ratio, not absolute pressure.
• Relatively low overall pressure drop. System recovers 65 to 80% of original pressure.
• High isentropic efficiency. Efficiency is around 90% compared with 75 to 85% for turboexpanders.
Cutaway view of Twister device.
Drawbacks of the system include:
• Requires a clean feed. Solids
erode the tubing and wing,
necessitating an inlet filter
separator.
• Limited turndown capacity. Flow
variability is limited to ±10% of
designed flow. This limitation is
mitigated by use of multiple tubes
in parallel.

Membranes
Schematic for membrane unit used as a fuel conditioner. (Adapted from Hale and Lokhandwala, 2004.)

Cooling by Expansion or External Refrigeration
Schematic of a direct refrigeration process for partial recovery of C2+ fraction. (Adapted from Engineering Data
Book, 2004e.)

Recent advances in turboexpander technology:
• Low gas rates. J-T is more economically viable at low gas rates.
Crum (1981) maintains that at below 10 MMscfd (300 MSm3/d),
turboexpanders offer less economic advantage and they lose
efficiency below
5 MMScfd (150 MSm3/d).
• Low ethane recovery. For ethane recoveries of 10 to 30%, J-T
expansion may be sufficient.
• Variable flow rates. J-T is insensitive to widely varying flow rates,
whereas turboexpanders lose efficiency when operating off of
design rates.

Lean Oil Absorption
Refrigerated lean oil absorption process. (Adapted from Engineering Data Book, 2004e.)
The process involves three steps
1. Absorption. An absorber contacts a
lean oil to absorb C2+ plus from raw
natural gas.
2. Stabilization. The rich oil
demethanizer (ROD) strips
methane and lighter components
from the rich oil.
3. Separation. The still separates
the recovered NGL components
as product from the rich oil, and
the lean oil then returns to the
absorber.

Schematic of conventional turboexpander process with no recycle to demethanizer. Note that the one heat exchanger
represents a network of exchangers. (Adapted from Engineering Data Book, 2004e.)

Cold-residue recycle process for maximizing ethane recovery. All valves in figure are J-T expander valves but are unlabeled
for figure clarity and the large heat exchanger represents a network of exchangers. (Adapted from Engineering Data Book,
2004e.)

Three sets of circumstances require nitrogen separation or rejection:
• Processing a gas high in nitrogen to produce a pipeline quality gas.
• Removing nitrogen from a natural gas so that the nitrogen can be used in an enhanced oil recovery (EOR) operation.
• Separating helium from nitrogen in a helium recovery operation.
NITROGEN REJECTION FOR GAS UPGRADING
• Cryogenic distillation
• Adsorption
• Membrane separation

CRYOGENIC DISTILLATION
NRU by use of two-column cryogenic distillation (Handwerk, 1990). Valves are J-T valves.

PRESSURE SWING ADSORPTION
The amount adsorbed depends on four factors:
1. The adsorbent itself
2. The species being adsorbed (adsorbate)
3. The temperature
4. The partial pressure of the adsorbate
Simple pressure swing adsorption (PSA) system.
Separating N2 from natural gas by use of membranes.

Schematic of an enhanced oil recovery (EOR) system.
enhanced oil recovery consists of
three separate units:
• An air separation plant to generate
nitrogen
• A gas plant to recover liquids from
the produced stream
• An NRU to produce a sales gas

Trace Component
Recovery or Removal
The components include:
• Hydrogen
• Oxygen
• Radon (NORM)
• Arsenic
• Helium
• Mercury
• BTEX (benzene, toluene,
ethylbenzene, and xylene)

HYDROGEN
Hydrogen levels are rarely sufficiently high to cause a problem, and no GPA specifications exist for maximum
levels in sales gas. The primary source would be gas streams from refineries, but even there, the concentrations
should be low.
OXYGEN
Oxygen is the only contaminant that is not naturally occurring, and the best approach for treating it is to prevent its
introduction into the processing stream. The major source of oxygen is leaking valves and piping in gathering
systems that operate below atmospheric pressure.
However, it causes problems in gas processing at concentrations of 50 ppmv, such as:
• Enhancing pipeline corrosion if liquid water is present
• Reacting with amines in gas treating, which ultimately leads to heat stable salt formation
• Reacting with glycols to form corrosive acidic compounds
• Reacting with hydrocarbons during the high-temperature regeneration of the adsorption beds to form water,
which reduces regeneration effectiveness and, thus, reduces bed capacity

RADON (NORM)
Natural gas contains radon, a naturally occurring radioactive material (NORM), at low concentrations, and it rarely
poses a health problem because it has a halflife of about 3.8 days (Encyclopedia Americana, 1979). However, radon
decays into lead-210, then to bismuth-210 and polonium-210 and finally into stable lead-206. These daughter
products of radon, some of which have long half-lives, condense on pipe walls and form a low-level radioactive
scale, which may flake off and collect on inlet filters. Because the boiling point of radon is −79.2°F (−61.8°C), it tends
to concentrate in propane and ethane−propane mixtures. Storage vessels can accumulate the daughter products as
sludge. Discarded piping with the scale generates large quantities of low-level radioactive waste that must be
discarded in disposal wells.
ARSENIC
Arsenic is a toxic nonvolatile solid but exists in natural gas predominately as a more volatile trimethylarsine (As
(CH3)3). It usually collects as a fine gray dust. High concentrations tend to be geographically localized. It can be
successfully removed from gas by use of a nonregenerative adsorption process. Several facilities reduce arsenic
concentrations in sweet raw gas from around 1,000 to less than 1μg/m3 (Rhodes, 2005). Without arsenic removal,
the gas streams could not be marketed. The process requires dehydration of the gas to pipeline specifications
before it goes to the adsorbers.

RECOVERY METHODS
Schematic of Ladder Creek Helium Recovery Plant (Johnson and Rydjord, 2001).
The plant was designed to process
35 MMscfd (1 MMm3/d), with
expansion capability to 50
MMscfd (1.4 MMm3/d). Helium
recovery was set at 95%, with the
ethane either rejected or
recovered. The natural gas liquids
(NGL) are recovered while
pipeline gas is produced. the
carbon dioxide content is first
reduced to less than 10 ppm,
and then trace quantities of
mercury present are removed
before dehydration by use of
molecular sieve beds.

(BTEX) BENZENE, TOLUENE, ETHYLBENZENE, AND XYLENE
The methods presently used to control BTEX emissions to the atmosphere are:
• Adjustment of plant operating conditions to minimize the quantity of BTEX in the glycol absorber off gas
• Burning of the still off gases before venting
• Condensation of the off gases and recovery of the BTEX as a liquid product
• Adsorption of the BTEX on a carbon adsorbent
Example - Compute the ratio of the minimum work of separation required to obtain
pure He from air compared with that from a natural gas that contains 3 mol% He in
the feed. Assume the separation takes place at constant temperature and that the
gases are ideal.

Solution:
The entropy change per mole of ideal gas mixture formed from pure components is
where R is the gas constant and xi is the mole fraction of component i. Because the He concentration is so low in air,
the mole fraction of the other components in air can be assumed to not change, so the change in entropy is
assumed to be caused by the change in He concentration only. We are interested in the ratio of work per mole of
He produced and base work on 1 mole of initial gas mixture.
Thus, the ratio of work is
If the two separations are performed at 100% thermodynamic efficiency at a constant temperature, the work required
to obtain helium from air would be 2.9 times greater than extracting it from natural gas.

Regenerative caustic wash and water wash.

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