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Surface Production OperationsENPE 505
1
ENPE 505Lecture Notes #5
Separation SystemsHassan Hassanzadeh
EN B204Mhhassanz@ucalgary.ca
Separation Systems
Learning Objectives
• identify factor affecting separation process
2
• distinguish appropriate separation vessels
• perform separator sizing calculations for oil, gas
and water separation processes.
• carry out design calculations associated with
selection of gas cleaning equipments.
Separation Systems
Proper separator design is important because a separation vessel is
normally the initial processing vessel in any facility, and improper design of
this process component can “bottleneck” and reduce the capacity of the
entire facility.
Separators are classified as “two-phase” if they separate gas from the
total liquid stream and “three-phase” if they also separate the liquid stream
3
total liquid stream and “three-phase” if they also separate the liquid stream
into its crude oil and water components.
Separators are sometimes called “gas scrubbers” when the ratio of gas
rate to liquid rate is very high.
Factors affecting separator design
Characteristics of the flow stream will greatly affect the design and operation of a
separator. The following factors must be determined before separator design:
1. Gas and liquid flow rates (minimum, average, and peak),
2. Operating and design pressures and temperatures,
3. Surging or slugging tendencies of the feed streams,
4
3. Surging or slugging tendencies of the feed streams,
4. Physical properties of the fluids such as density and compressibility factor.
5. Designed degree of separation (e.g., removing 100% of particles greater than
10 microns),
6. Presence of impurities (paraffin, sand, scale, etc.),
7. Foaming tendencies of the crude oil,
8. Corrosive tendencies of the liquids or gas.
Separation Systems (cont.)
A separator is normally constructed in such a way that it has the following
features:
1. A centrifugal inlet device for primary separation of the liquid and gas
2. Provides a large settling section of sufficient height or length to allow liquid
droplets to settle out of the gas stream with adequate surge room for slugs of
liquid.
5
3. Equipped with a mist extractor or eliminator near the gas outlet to coalesce small
particles of liquid that do not settle out by gravity.
4. Allows adequate controls consisting of level control, liquid dump valve, gas
backpressure valve, safety relief valve, pressure gauge, gauge glass, instrument
gas regulator, and piping.
1. Centrifugal action
2. Gravity settling
3. ImpingementMechanical Separation
1. Inlet diverter section
2. Liquid collection section
3. Gravity settling section (dp>100-140 µ)
4. Mist extractor section (dp<100-140 µ)
Functional sections of a gas-liquid separator
1 3
2
4
6
Other separatorsDouble-barrel horizontal separator
Possibility of large liquid slugs
horizontal separator with a boot
7http://cgm-ing.com/twister/news/separation-goes-supersonic/
Venturi Separators
Centrifugal Separator or cylindrical
cyclone separators (CCS)
100 to 50,000 bbl/d
2 to 12 in diameter
Best suited for clean gas streams
No moving parts
Low maintenance
Compact, in terms of weight and space
Low cost
Design is rather sensitive to flow rate
Large pressure drop
Other separators (cont.)
Filter separator
½ inch thick cylinder fiberglass
surrounds the perforated metal
cylinder. A micron fiber fabric
layer is located on both sides of
8
1. High gas and low liquid flow applications
2. Horizontal or vertical
3. Compressor inlet
4. Final scrubber upstream of glycol contactor
5. Removal of 100% of 1µ particles to 99% of ½ µ liquid particles
layer is located on both sides of
the fiberglass.
Other separators (cont.)
Scrubbers
A scrubber is a two-phase separator that is designed
to recover liquids carried over from the gas outlets of
Separators are sometimes called “gas scrubbers”
when the ratio of gas rate to liquid rate is very high.
9
to recover liquids carried over from the gas outlets of
production separators or to catch liquids condensed
due to cooling or pressure drop.
Applications include upstream of mechanical
equipment such as compressors, upstream of gas
dehydration equipment.
Other separators (cont.)Slug Catcher
A "slug catcher," commonly used in gas gathering pipelines, is a special case of two-
phase gas-liquid separator that is designed to handle large gas capacities and liquid
slugs on a regular basis. Since the gathering systems are designed to handle
primarily gas, the presence of liquid restricts flow and causes excessive pressure drop
in the piping. Pigging is periodically used to sweep the lines of liquids. When the pigs
sweep the liquid out of the gathering lines, large volumes of liquids must be handled
by the downstream separation equipment. The separators used in this service are
called slug catchers.
10http://www.tfes.com
Separator internalsInlet diverters
Inlet diverters serve to impart flow
direction of the entering vapor/liquid
stream and provide primary separation
between the liquid and vapor.
Baffle diverter
Centrifugal diverter
11
Elbow diverter
Separator internals (cont.)
In long horizontal vessels, usually located on floating structures, it may be
necessary to install wave breakers. The waves may result from surges of liquids
Cyclone baffle
Tangential raceway
Wave Breakers
12
necessary to install wave breakers. The waves may result from surges of liquids
entering the vessel. Wave breakers are nothing more than perforated baffles or
plates that are placed perpendicular to the flow located in the liquid collection
section of the separator. These baffles dampen any wave action that may be
caused by incoming fluids. The wave action in the vessel must be maintained so
that liquid level controllers, level safety switches, and weirs perform properly on
floating or compliant structures where internal waves may be set up by the
motion of the foundation.
Separator internals (cont.)
Defoaming Plates
Foam at the interface may occur when gas
bubbles are liberated from the liquid. Foam can
severely degrade the performance of a separator.
This foam can be stabilized with the addition of
chemicals at the inlet. Many times a more effective
solution is to force the foam to pass through a
series of inclined parallel plates or tubes.
13
series of inclined parallel plates or tubes.
Vortex Breaker
Liquid leaving a separator may form
vortices or whirlpools, which can pull gas
down into the liquid outlet. Therefore,
horizontal separators are often equipped
with vortex breakers, which prevent a
vortex from developing when the liquid
control valve is open.
These closely spaced plates or tubes provide additional surface area, which break
up the foam and allow foam to collapse into the liquid layer
Separator internals (cont.)
A stilling well, which is simply a slotted pipe fitting surrounding an internal
level control displacer, protects the displacer from currents, waves, and other
disturbances that could cause the displacer to sense an incorrect level
measurement.
Stilling Well
Sand jets and drains
In horizontal separators one worry is the accumulation of sand and solids
14
In horizontal separators one worry is the accumulation of sand and solids
at the bottom of the vessel. If allowed to build up, these solids will upset
the separator operations by taking up vessel volume. In addition accumulation
of such solid material promote corrosion. Generally, the solids
settle to the bottom and become well packed. To remove the solids, sand
drains are opened in a controlled manner, and then high-pressure fluid, usually
produced water, is pumped through the jets (20 ft/s) to agitate the solids and
flush them down the drains. Drain and its associated jets, should be installed
at intervals not exceeding 5 ft.
Mist extractorImpingement type is the most widely used mist eliminator. This type offers
good balance between efficiency, operating range, pressure drop
requirement, and installed cost. It consists of baffles, wire meshes, and
micro fiber pads.
When a fluid stream approaching a target (baffle or disc) droplets can be captured by
target via any of the following mechanisms:
Inertial impaction: because of their mass, particles 1-10 microns in diameter in the gas
stream have sufficient momentum to break through the gas streamlines and continue to
move in a straight line until they impinge on the target.
Direct interception: Particles 0.3 to I microns do not have sufficient momentum to
15
Direct interception: Particles 0.3 to I microns do not have sufficient momentum to
break through the gas streamlines. Instead, they are carried around the target by the
gas stream. However, if the streamline in which the particle is traveling happens to lie
close enough to the target so that the distance from the particle centerline to the target
is less than one-half the particle's diameter, the particle can touch the target and be
collected. Interception effectiveness is a function of pore structure. The smaller the
pores, the greater the media to intercept particles.
Diffusion: smaller particles, usually smaller than 0.3 microns in diameter, exhibit
random Brownian motion caused by collisions with the gas molecules. This random
motion will cause these small particles to strike the target and be collected, even if the
gas velocity is zero. Typical velocity ranges from 1-4 ft/min.
Separation principles
Impingement
Gas entertained liquid particles strikes a surface such as baffle plate,
or wire mesh. The gas flows around the flow obstruction, but the liquid
droplet impinge and collect on the surface
16Impingement technique can usually handle droplets down to a size of 5 microns
Mist extractors (cont.)
∼10-40 micron in diameter liquid droplets
∼10-15 mm H2O pressure drop
17
5-75 mm space between plates, and total depth of 150-300mm
Mist extractors (cont.)
An "arch" plate type mist extractorvane-type mist extractor made from angle iron
18
knitted mesh mist eliminator
www.amistco.com
3-7 in in thickness and mesh density of
10-12 lb/ft3. constructed from wires of
0.1-0.28 mm with a void fraction of
0.95-0.99.
Mist extractors (cont.)
3-10 micron in diameter liquid droplets
wire-mesh mist extractor
19
Dimensions for the placement of a wire-mesh mist extractor.[ H represents
minimum height, and H, must be at least 1 foot (305mm).]
Mist extractors (cont.)
Micro-fiber mist extractors use very small diameter fibers, usually less
than 0.02 mm, to capture very small droplets. Gas and liquid flow is
horizontal and co-current. Because the micro-fiber unit is manufactured
from densely packed fiber, drainage by gravity inside the unit is limited.
Much of the liquid is eventually pushed through the micro-fiber and drains
downstream face. The surface area of a micro fiber mist extractor can be 3 to 150 times that of a wire mesh unit of equal volume.
20
Typical velocity ranges from 20-60 ft/min for impaction type and 1-4 ft/minfor diffusion type.
Mist extractors (cont.) Centrifugal mist extractor
A coalescing pack mist extractor
21
These units can be more efficient
than either wire-mesh or vanes and
are least susceptible to plugging.
However, they are not in common
use in production operation because
their removal efficiencies are
sensitive to small change in flow
rate. In addition, they require large
pressure drop to create centrifugal
forces.
Potential operating problemsFoamy crudePresence of impurities, other than water such as CO2, completion and
workover fluids, and corrosion inhibitors, that are incompatible with the
wellbore fluids. Foaming causes:
1. Difficulty in level control
2. It can occupy much of the separator volume because large volume to
weight of foam decreasing separation efficiency.
3. Entertainment of foam in oil and gas streams
22
The foaming tendencies of a crude oil can be determined with laboratory tests
(ASTM D892).
Paraffin
Accumulation of paraffin in the liquid section and mesh pad mist extractors in
the gas section.
When paraffin is a problem, the use of plate type or centrifugal mist extractors
should be considered. Manways, handholes, and nozzles should provided to
allow steam, solvent, or other type of cleaning of the separator internals. The
bulk temperature of the liquid should always be kept above the cloud point of
the crud oil. The cloud point of a fluid is the temperature at which dissolved solids are no longer completely soluble,
precipitating as a second phase giving the fluid a cloudy appearance
Potential operating problems (cont.)Sand production
Sand production can be very problematic by causing cutout of valve
trim, plugging of separator internals, and accumulation in the bottom of
the separators.
Liquid carryover
Liquid carryover occurs when free liquid escapes with the gas phase. Liquid
carryover can indicate high liquid level, damage to vessel internals, foam,
improper design, plugged liquid outlets, or a flow rate exceeds the vessel’s
design rate. It can be prevented by installation of level safety high sensor.
23
design rate. It can be prevented by installation of level safety high sensor.
Gas blowby
Gas blowby occurs when free gas escapes with the liquid phase and can be
an indication of low liquid level, vortexing, or level control failure. It can be
prevented by installation of level safety low. In addition, downstream process
components should be equipped with a pressure safety high sensor and a
pressure safety valve sized for gas carry through.
Liquid slugs
Two-phase flow lines and pipelines tend to accumulate liquids in low spots in
the lines. When the level of liquid in theses low spots rises high enough to
block the gas flow, then the gas will push the liquid along the line as a slug.
Separation principles
rdF lpa
23
6ωρ
π=
( )Q
hRRt io
22 −=
π
lp rddrv
ωρ4 2
==
Centrifugal Separation ω
FaFd
Residence time = Centrifuge volume/flow rate
222
82
1pgdgdd dvCAvCF ρ
πρ ==
At equilibrium F =F
Drag force
24
gd
lp
C
rd
dt
drv
ρ
ωρ
3
4==At equilibrium Fd=Fa
( )lp
gdio
d
CRRt
ρ
ρ
ω
3−=
( )22
2223
ωρπ
ρ
l
gdio
ph
QCRRd
−=
To decrease the droplet size that can be removed,
1. Decrease Q (not feasible)
2. Increase height
3. Increase rotational speed
Centrifugal separation can usually handle droplets down to a size of 2 microns
Centrifugal
force
Separation principles
( ) 3
6pglg gdF ρρ
π−=
( ) ( )gd ρρρρ −−4
Gravity Segregation
Fg
Fd
22
8pgdd dvCF ρ
π=
At equilibrium F =F
hfeed
25
( ) ( )g
gl
gd
glpK
C
gdv
ρ
ρρ
ρ
ρρ −=
−=
3
4
Q
Lh
Q
Vt
4
2π==
At equilibrium Fd=Fg
To allow smaller droplet to settle we should maximize the diameter and L
Sounders-Brown equation
t
hv
dt
dhv =⇒=
4
hLvQ
π=
( )gd
glp
C
gdhLQ
ρ
ρρπ
3
4
4
−=
Gravity Segregation can usually handle droplets down to a size of 80 microns
Effect of Pressure and Temperature
1. Separator pressure, temperature and feed composition2. As the pressure increases, or the temperature decreases, there is a
greater oil liquid recovery, up to a point called the optimum, flash calculations will yield the optimum condition.
3. From practical point of view it may not be possible to operate at this optimum point because of the costs involved, operational problems, or enhanced storage system vapour losses.
26
enhanced storage system vapour losses.4. Generally, separator gas capacity increases with increasing pressure
and decreasing temperature. This is because of pressure and temperature effects on gas and liquid densities, actual volume and allowable velocity through separator.
5. Economic is the foremost concern in actual field operations6. Product sale specification must be considered (oil API, gas BTU/vol.)
Separator sizing and selection1. The design aspects encountered by a petroleum engineer only
involve choosing the correct separator size for a given field installation.
2. Separator sizing is essentially quoted in terms of gas and liquid capacities.
3. Other parameters such as pressure drop through separator, are specified for a given design by the manufacturer
27
( )g
gl
g Kvρ
ρρ −=
specified for a given design by the manufacturer
Gas CapacityThe Souders–Brown equation is widely used for calculating gas capacity of
oil/gas separators:
ρL = density of liquid at operating conditions, lbm/ft3
ρ g = density of gas at operating conditions, lbm/ft3
K = empirical factor,
D is in ft,
Qgsc is in MMSCFD ( )( )
g
gl
gscTZ
KpDQ
ρ
ρρ −
+=
460
4.2 2
K Values Used for Selecting Separators (Sivalls, 1977)
Separator type K Most commonly used K
Vertical separators 0.06–0.35 0.117 with a mist extractor
0.167 without a mist extractor
Horizontal separators 0.40–0.50 0.382 with a mist extractor
Spherical - 0.35 with a mist extractor
Wire mesh mist eliminators 0.35
Separator sizing and selection
28
Wire mesh mist eliminators 0.35
Bubble cap trayed columns 0.16 (24-in. spacing)
Valve tray columns 0.18 (24-in. spacing)
The Souders–Brown equation can be used to calculate separator diameter
( )g
g
gg
g
gl
gv
QDDAAvQKv
π
π
ρ
ρρ 4,
4,, 2 ===
−=
Separator sizing and selectionLiquid Capacity
The liquid capacity of a separator relates to the retention time through the
settling volume:
t
VQ l
l
1440=
QL = liquid capacity, bbl/day
VL = liquid settling volume, bbl
t = retention time, min
VL = 0.1339D2h for vertical separators, in bbl
VL = 0.1339D2(L/2) for horizontal single-tube separators, in bbl
VL = 0.1339D2(L) for horizontal double-tube separators, in bbl
29
VL = 0.1339D (L) for horizontal double-tube separators, in bbl
VL = 0.0466D3(D/2)0.5 for spherical separators, in bbl
L and h are in ft
For a good separation, a sufficient retention time, t, must be provided. From field experience (Sivalls, 1977) Oil & gas separation t= 1 minHigh pressure oil-water-gas t=2-5 minLow pressure oil-water-gas t=5-10 min @ T>100 F
t=10-15 min @ 90 oFt=15-20 min @ 80 oFt=20-25 min @ 70 oFt=25-30 min @ 60 oF
Design considerations (Lockhart et al, 1986)
1. For a horizontal or vertical separator L/D should be kept 3 to 83 to 8due to consideration of fabrication cost, etc.
2. For a vertical separator, the vapour-liquid interface (at which the feed enters) should be at least 2 ft from the bottom and 4 ft from the top of the vessel. This implies a minimum vertical separator height (length) of 6 ft6 ft.
3. For a horizontal separator, the feed enters just above the vapour-liquid interface that may be off-centered to adjust for a gas (or
30
liquid interface that may be off-centered to adjust for a gas (or liquid) capacity as needed. The vapour-liquid interface, however, must be kept at least 10 inches from the bottom and 16 inches from the top of the vessel. This implies a minimum diameter of minimum diameter of 26 inches26 inches.
4. In practice these rules of thumbs may be violated for providing additional features. Therefore standard vertical separators less than 6 ft and horizontal separators of diameter 26 inches are available in the industry.
Design considerations (Lockhart et al, 1986)
5. High-pressure separators are generally used for high
gas-oil ratio (gas and gas condensate) wells. In this
case, the gas capacity of the separator is the limiting
factor.
6. Low-pressure separators are generally used for low
gas-oil ratio wells. In this case, the liquid capacity of
the separator is the limiting factor.
31
the separator is the limiting factor.
7. The separator chosen must satisfy both the gas as
well as liquid capacities.
8. As the GLR increases, the retention time decreases.
tQV
tQGLRV
VVV
LL
LG
LG
=
××=
−= ,
( )GLRQ
VttQVtQGLR
L
LL+
=⇒−=××1
VG
Separator design using actual
separator performance chart
The Sounders-Brown relationship provides only an
approximate approach.
A better design can usually be made using actual
manufacturers’ field test data that accounts for the
32
manufacturers’ field test data that accounts for the
dependence of capacity on separator height (for
vertical) or length (for horizontal).
Gas capacity of vertical LP separator
33After Sivalls
Gas capacity of vertical HP separator
34After Sivalls
Gas capacity of horizontal LP separator
35After Sivalls
Gas capacity of horizontal HP separator
36After Sivalls
Gas capacity of horizontal HP separator
37After Sivalls
Gas capacity of spherical separator
38After Sivalls
Liquid capacity of horizontal single-tube HP separator
39After Sivalls
Liquid capacity of horizontal single-tube HP separator
40After Sivalls
Arnold and Stewart approach
,32
DF
VACF
πρρ ∆==
Design theory
In the gravity settling section of a separator, liquid droplets are removed
using the force of gravity. Liquid droplets, contained in the gas, settle at
a terminal or "settling" velocity. At this velocity, the force of gravity on
the droplet or "negative buoyant force" equals the drag force exerted on
the droplet due to its movement through the continuous gas phase. The
drag and buoyant forces on a droplet may be determined from the following
equations:
41
6 ,
2
DF
g
VACF BgdDD
πρρ ∆==
VDFD '3πµ=⇒
'18
2
µ
ρDVt
∆=
equations:
If the flow around the droplet is laminar (Re<1) CD=24/Re
The drag force on a falling droplet is given by:
When the drag force is equal to the buoyancy force, the droplet’s acceleration is
zero so that it moves at a constant terminal velocity.
Stokes’ law
, where µ is in cp and µ’ is in lbf-sec/ft2
µ
γ 261078.1 mt
dV
∆×=
−
, where µ is in cp, dm is in micron, γ is specific gravity
Design theory (cont.)Unfortunately, for production facility designs it can be shown that
Stokes' law does not govern, and the following more complete formula
for drag coefficient must be used
µ
ρ Vdmg0049.0Re =
dm in micron, ρg in lbm/ft3,
V in ft/s, µ in cp
42
Equating drag and buoyant
forces, the terminal settling
velocity is given by (field
units)
For CD = 0.34 0.0204 dm , dm in micron
V in ft/s, µ in cp
Design theory (cont.)Droplet size
From field experience, it appears that if 140 micron droplets are removed in
the gravity settling section, the mist extractor will not become flooded and will
be able to perform its job of removing those droplets between 10- and 140
micron diameter. Therefore, the gas capacity design equations are all based
on 140 micron removal.
Retention time
Defined as the average time a
molecule of liquid is retained in
43
molecule of liquid is retained in
the vessel, assuming plug
flow. The retention time is thus
the volume of the liquid
storage in the vessel divided
by the liquid flow rate.
Liquid re-entrainment is a phenomenon caused by high gas velocity at
the gas-liquid interface of a separator. Momentum transfer from the gas
to the liquid causes waves and ripples in the liquid, and then droplets are
broken away from the liquid phase.
Design theory (cont.)
36714442
1
42
1 ,
222 dd
DAA
QV g
g
g =
=
==
ππ
2120
Pd
ZTQV sc
g =
Assuming a horizontal vessel is full half of liquid . Gas velocity is given by:
Horizontal separator design
Q in terms of ft/sec is given by:
where Qsc is in MMSCFD, d is in inches, p is in psia, and T is in oR.
P
ZTBg 02728.0=
P
ZTQBQQ scgsc
327.0360024
106
=×
×=
44
Pd
tt
d
sc
eff
g
eff
gV
d
V
Dt
Pd
ZTQ
L
V
Lt
242 ,
1202
==
==
Set the residence time of the gas equal to the time required for the droplet to fall
to the gas liquid interface
We have
Setting td=tg
Design theory (cont.)
l
eff
llQ
LdtQQQ
2
5 42105.6360024
62.5=⇒×=
××= −
Two-phase separators must be sized to provide some liquid retention time so
the liquid can reach equilibrium with the gas. For a vessel 50% full of liquid,
and with a specified liquid flow rate and retention time:
eff
effeffLd
LdLDV
Q
Vt
23
22
1073.214442
1
42
1 , −×=
×=
==
ππ
Ql is in BPD, Q is in ft3/sec.
Ld2
42 60
sec.
45
l
eff
Q
Ldt
2
60
42= in min. tQLd leff
42
602 =
Seam-to-Seam LengthFor vessels sized on a gas capacity basis, some portion of the vessel length is
required to distribute the flow evenly near the inlet diverter. Another portion of the
vessel length is required for the mist extractor. The length of the vessel between the
inlet diverter and the mist extractor with evenly distributed flow is the Leff. The seem
to seam length may be estimated as the larger of the following:
Lss = Leff +d/12 or Lss = (4/3)Leff for gas capacity
For vessels sized based on a liquid capacity basis Lss = (4/3)Leff
Design theory (cont.)
1. Equations described allow for various choices of diameter and length. For each vessel design, a combination of Leff and d exists that will minimize the
cost of the vessel.
2. It can be shown that the smaller the diameter, the less the vessel will weigh
and thus the lower its cost. There is a point, however, where decreasing
the diameter increases the possibility that high velocity in the gas flow will
Slenderness ratio (L/d)
46
the diameter increases the possibility that high velocity in the gas flow will
create waves and re-entrain liquids at the gas-liquid interface.
3. Experience has shown that if the gas capacity governs and the length
divided by the diameter, referred to as the "slenderness ratio," is greater
than 4 or 5,re-entrainment could become a problem.
4. Most two-phase separators are designed for slenderness ratios between 3
and 4. Slenderness ratios outside the 3 to 4 range may be used, but the
design should be checked to assure that re-entrainment will not occur
Horizontal separators sizing other than half full
Gas capacity
47
Liquid capacity
If β is known, α can be determined from a chart in the next slide.
Gas and liquid capacity constraint design constant vs. liquid height of a cylinder for a horizontal separator other than 50% full of liquid ( field units).
Gas capacity
Liquid capacity
ββββ
48
ββββ
αααα αααα
Design theory (cont.)
, ,22
2 ddDA
QV gg =
=
==ππ
P
ZTBg 02728.0=
By setting the gas retention time equal to the time
required for a droplet to settle to the liquid interface,
the following equation may be derived
ZTB 02728.0=
Vertical separator-Gas capacity
49
,18314444
, DAA
V g
g
g =
=
==P
Bg 02728.0=
P
ZTQBQQ scgsc
327.0360024
106
=×
×=
260
Pd
ZTQV sc
g =
tg VV =
Design theory (cont.)Vertical separator-Liquid capacity
h in inch
ft3/sec
50
In vertical separators whose sizing is liquid dominated, it is common to choose
slenderness ratios no greater than 4 to keep the height of the liquid collection
section to a reasonable level. Choices of between 3 and 4 are common, although
height restrictions may force the choice of a lower slenderness ratio.
sec
Stage separationWhen two or more equilibrium separation stages are used in series, the
process is termed “stage separation.”
Although three to four stages of separation theoretically increase the liquid
Prediction of the performance of the various separators in a multistage
separation system can be carried out with compositional computer models
51
Although three to four stages of separation theoretically increase the liquid
recovery over a two-stage separation, the incremental liquid recovery rarely
pays out the costcost ofof thethe additionaladditional separatorsseparators. It has been generally
recognized that two stages of separation plus the stock tank are practically
optimum. The increase in liquid recovery for three-stage separation over two-
stage separation usually varies from 22 toto 1212%%,, depending on wellstream
composition and P&T although 2020 toto 2525%% increases in liquid recoveries have
been reported.
Stage separation
Np
3rd stage
10-75 psig Stock
2nd stage
100-500 psig
1st stage gas
2nd stage gas
Vent gas1st stage
500-1500 psig
Well stream fluid3rd stage gas
4 stage separation
52
Np
3 stage separation
10-75 psig Stock
tank
1st stage
100-500 psig
2nd stage
10-75 psig Stock
tank
Well stream fluid
1st stage gas2nd stage gas Vent gas
Np
Stage separation
1st stageStock
tankWell stream fluid
1st stage gas Vent gas
Np
1st stage
10-100 psig Stock
tankWell stream fluid
1st stage gas Vent gas
Np
2 stage separation
53
2nd stage
40-100 psig
1st stage
400-1000 psig
Stock
tank
Well stream fluid
1st stage gas2nd stage gas Vent gas
Np
Alternative
Arrangement for 3
stage separation
Stage separation
stN
s
pp
pR
1
1
=
Pressures at low-stage separations can be determined based on equal
pressure ratios between the stages (Campbell, 1976):
where
Rp = pressure ratio
Nst = number of stages -�1
54
Nst = number of stages -�1
p1 = first-stage or high-pressure separator pressure, psia
ps = stock-tank pressure, psia
Pressures at the intermediate stages can then be designed with the following
formula:
p
ii
R
pp 1−=
where pi = pressure at stage i, psia.
Stage separation
( )057.0686.0
12
−+=
AApp
The equal pressure ratios bear no relationship with the magnitude of
separation (i.e., the LGR)
Whinery and Campbell (1958) studied three-stage separation for several
different types of well streams
For streams with specific gravity >1 (air=1)
55
0233.012 += App
For streams with specific gravity <1 (air=1)
( )012.0
028.0765.0
12
−+=
AApp
Relationship between A and pseudo-specific
gravity of feed (T=80oF), SPE, 1958
Low temperature separationLow-temperature separation units are based upon principle that lowering the
operating temperature of a separator increases the liquid recovery. In
addition, it dehydrates the gas.
∆p=pinitial-pfinal
Based on 25% liquid
Approximate temperature correction for hydrocarbon liquid content of a water free well stream
56
Temperature drop accompanying a given Pressure drop (Eng. Data Book, GPSA)
∆T (oF)
pinitial
Based on 25% liquid condensed on expansion and % liquid recovered in stock tank
Gas cleaningGas cleaning is important for pipeline transportationsystem in order to:
1. Reduce the operational problems
2. Maximize operating efficiency
3. Gas storage
4. Sale specifications
57
4. Sale specifications
5. Prevent catalyst and solution contamination
First phase of cleaning at the wellhead by such means of
strainer,
sand traps and filters.
Second phase of cleaning is carried out in the gas liquid
separators.
Further cleaning is required before the gas arrives at a
processing plant, and before the processing is begun.
Gas cleaning
A clean up gas transmission averages about 2 lbm/MMSCF
particulate matter in the gas
Gas cleaning involves the removal of two types of materials
1.Gross solids and liquids, called “pipeline trash” or sludge.
58
1.Gross solids and liquids, called “pipeline trash” or sludge.
This consists of liquids such as heavier end hydrocarbons,
water, chemicals such as amines, glycols, methanol, corrosion
inhibitors, drilling muds, pipeline scales such as corrosion
products.
2.solid particles and liquid (aerosols). These are suspended
solids or liquids and are much more difficult to remove
because of their ultra-small particle size.
Gas cleaning
( ) n
nn
gp
n
p
C
adv
−
−
+
−=
2
1
1
1
3
4
ρµ
ρρ
General equations for particles suspended in a gas
The terminal velocity of a particle falling through a fluid under the
influence of a force that exerts an acceleration on the particle is:
v= velocity in ft/s
a= acceleration in ft/s2
dp=, particle diameter in ft
ρg = gas density in lbm/ft3
ρ = particle density in lbm/ft3
59
n
g
n
gdC 13 ρµ ρp= particle density in lbm/ft3
µg = gas viscosity, lbm/ft.s
The drag coefficient Cd and exponent “n” are as follows (Lapple, 1984):
Flow regime NRe Law Cd n Remark
Laminar <0.3 Stokes 24 1 Small dp
Intermediate 0.3-103 Intermediate 18.5 0.6
Turbulent 103-2×105 Newton 0.44 0 Large dp
NRe= ρgvdp/ µg
Gas cleaning
For small particles less than 3For small particles less than 3 micronsmicrons the Stokes law is
no longer valid. In this case the particles are so small that
they slip between the gas molecules at a rate greater than
that predicted by Stokes law.
For particles smaller than 3 microns, a random motion,
60
For particles smaller than 3 microns, a random motion,
known as Brownian movement, also begins to occur. Its
effect superimposed upon the particle settling velocity,
and for particles under 0.1 microns, Brownian motion
becomes the dominant phenomenon. Gas cleaning is
never really persuade to such levels.
Typical process applications and operating range of equipment
61
Sulzer Chemtech
Gas cleaning methods1. Gravity settling2. Centrifugal action3. Impingement4. Filtration5. Scrubbing6. Electrostatic precipitation
1.1. Wire mesh padsWire mesh pads can remove droplets down to 4 microns in size.
2. A Gas flow velocity of 5-10 ft/s provides maximum operation efficiency.
62
1. The vanevane--typetype designed for horizontal
flow through the vanes.
2. The pressure drop is very small
3. It can handle solids
4. It can remove droplets about 40 microns
1.1. Fiber mist eliminatorFiber mist eliminator offers high efficiency up to 99.98%
2. Can handle mists smaller than 3 microns
2. A Gas flow velocity of 5-10 ft/s provides maximum operation efficiency.
3. Designed for vertical flow
Gas cleaning methods
FiltersFilters have been traditionally used to remove solids particles by using a
filtration medium that allows only gas to pass through. Bag filters using
woven fabric or compressed felt fabric, glass fibers have been used.
ScrubbersScrubbers may use liquids to aid the removal of a particles from gas.
Scrubbers include dry, oil bath, and cartridge type. Dry and oil bath
scrubbers can be effective down to almost 4 microns particles size.
63
scrubbers can be effective down to almost 4 microns particles size.
Cartridge type are very effective and can remove solid particulate
matter down to a size of 0.3 micron but require more maintenance
and thus expensive.
Electric precipitatorsElectric precipitators (ESP) induce an electrical charge that attracts the
particulate matter. A strong electrostatic field is provided that ionizes the
gas to some extent. The particle suspended in this partially ionized gas
become charged and migrate under the action of the applied electric
field.
Strainers Strainers are device which helps in restricting flow of unwanted particles
like pipeline debris or seal/jointing compound, weld metal, scaling and other solids in flowing liquids or gases, which may damage the down stream equipment or reduce the efficiency.
A pump or compressor shall have suction strainers so that clean fluid enters into the system.
64
A strainer should be fitted at upstream of every steam trap, flow meter and control valve to avoid malfunctioning.
Strainers can be classified according to their body configuration or shape: e.g.
1. Y-type2. Basket type or “Tee” type 3. Bucket type4. Conical
Y-type Strainers
Inlet
Filter
Outlet
65
1. Horizontal steam or gas lines should be installed in such a manner
so that the pocket is in the horizontal plane.
2. On liquid system the pocket should point vertically downwards
3. Installation of Y-type strainer is not possible in case of vertical line
upward flow
4. In vertical line downward flow it is possible and very effective.
Caphttp://maintenanceengineering.in
Basket type or “Tee” type strainer
66
1. For very high flow
2. Can be installed in horizontal pipe line or vertical line in downward flow only
3. The pressure drop across the strainer is less then Y-type strainer
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Temporary Strainers mounted between two flanges as protection of pipelines
and plants.
Bucket and Conical Type Strainers
67
1. Thin or low viscosity fluids or gases
2. Provide higher straining areas than
any other type of strainers
3. Can be installed in horizontal lines
only
4. Rate of increase of pressure drop is
normally very slow as compares to
conical strainers
1. These are conical in shape and
can be installed in either
direction, over the cone or under
the cone.
2. Can be installed in any pipelines
and are preferred in case gases
where flow is very high
Conical Type StrainersBucket Type Strainers
Typical strainer pressure drop chart
1000
10000
100000
Flo
w R
ate
(G
PM
)
30"
16"
68
10
100
1000
0.1 1 10
Pressure Loss (psi)
Flo
w R
ate
(G
PM
)
4"
Sand Traps
The migration of formation sand caused by the flow of reservoir fluids.
Sand drops out from reservoir well-streams into surface facilities.
The production of sand can:
1. Take up valuable separation volume, reducing residence time
2. Restrict productivity
69
KW International
2. Restrict productivity
3. Stabilise unwanted emulsions formed by the oil and water
4. Erode completion components,
5. Presents a major safety risk
6. Impede wellbore access
7. interfere with the operation of downhole equipment
8. Present significant disposal difficulties.
Three-phase oil and water separators
Three-phase separator and free-water knockout are terms used to describe
pressure vessels that are designed to separate and remove the free water
from a mixture of crude oil and water. Because flow normally enters these
vessels directly from either (1) a producing well or (2) a high pressure
separator, the vessel must be designed to separate the gas that flashes
from the liquid as well as separate the oil and water.
Three-phase separator: when there is a large amount of gas to be separated
70
Three-phase separator: when there is a large amount of gas to be separated
Free-water knockout: when the amount of gas is small relative to the amount of oil
and water.
3-30 min
water
oil
Three phase separators
Inlet diverter illustrating principles
of water washing
oil
Schematic of a horizontal three-phase
separator
71
water
1. Gas-oil Interface at 50-75% of
separator diameter.
2. Separators with bucket and weir are
more suitable for high WOR wells or
small density differences.
3. Separators with interface level control
is good for high oil rate and large
density differences.
4. Separators with bucket and weir are
more suitable for heavy oil.with bucket and weir
with interface level control and weir
Three phase separators (cont.)
72
Horizontal and vertical free-water knockout
Three phase separators (cont.)Horizontal three phase separator with flow splitter
73
Horizontal three phase separator with a liquid boot
Three phase separators (cont.)
74
a vertical three-phase separator
with interface level control
Cutaway view of a vertical three-
phase separator without water
washing and with vane mist extractor
Three phase separators (cont.)
Horizontal vessels are most economical for
normal oil-water separation, particularly where
there may be problems with emulsions, foam,
or high gas-liquid ratios.
Vertical vessels work most effectively in low
gas-oil ratio (GOR) applications and where
solids production is anticipated
75
Cutaway view of a vertical three-phase
separator without water washing and
with wire-mesh mist extractor Liquid level control schemes
Three-phase separators (cont.)Coalescing plates
Turbulent Flow Coalescers
76
It is possible to use various plate or pipe
coalescer designs to aid in the coalescing of
oil droplets in the water and water droplet in
the oil. The installation of coalescing plates in
the liquid section will cause the size of the
water droplets entrained in the oil phase to
increase, making gravity settling of these
drops to the oil-water interface easier. This
may lead smaller vessel but there is a
potential for plugging with sand, paraffin, or
corrosion products
Horizontal three-phase
separator fitted with free-
flow turbulent coalescers
(SP Packs)
Potential operating problems
Three-phase separators may experience the same operating problems as
two-phase separators. In addition, three-phase separators may develop
problems with emulsions which can be particularly troublesome in the
operation of three-phases separators. Over a period of time an
accumulation oil emulsified materials and/or other impurities may form at
Emulsions
77
accumulation oil emulsified materials and/or other impurities may form at
the interface of the water and oil phases. In addition to adverse effects on
the liquid level control, this accumulation will also decrease the effective
oil or water retention time in the separator, with a resultant decrease in
water-oil separation efficiency. Addition of chemicals and/or heat often
minimizes this difficulty.
Frequently, it is possible to appreciably lower the settling time necessary
for water-oil separation by either the application of heat in the liquid
section of the separator or the addition of de-emulsifying chemicals.
Three-phase water oil separator design theory
Example water droplet size distribution. Size distribution varies widely for different process
78
for different process conditions and water properties
Three-phase Horizontal water oil separator design
Gas capacity
Horizontal separator
Horizontal separator
79
Three-phase Horizontal water oil separator design (cont.)Horizontal separator
80
Settling water droplets from oil phase
This is the maximum thickness the oil pad can be and still allow the water droplets to
settle out in time tro
( ) ( )µ
SGtor
dm ∆==
320500
sec.
Three-phase Horizontal water oil separator design (cont.)
For a given oil retention time and a given water retention time, the maximum
oil pad thickness establishes a maximum diameter in accordance with the
following procedure:
( )( ) ( )
µ
SGth or
o
∆= 320
max
1. Compute (ho)max. Using 500 micron droplet if no other information is available
2. Calculate the fraction of the vessel cross-sectional area occupied by water
81
2. Calculate the fraction of the vessel cross-sectional area occupied by water
phase given by:
Three-phase Horizontal water oil separator design (cont.)
3. Determine β4. Calculate dmax using
Any combination of d and Leff, that
82
Any combination of d and Leff, that
satisfies the following equations:
will meet the necessary criteria.
Three-phase Horizontal water oil separator design (cont.)
Settling water droplets from oil phase
( ) ( )
w
ord SGtm
µ
∆==
2.51200
w
w
w w
w
ww
w
83
wµw
Seam-to-Seam Length
For vessels sized on a gas capacity basis, some portion of the vessel length is
required to distribute the flow evenly near the inlet diverter. Another portion of the
vessel length is required for the mist extractor. The length of the vessel between the
inlet diverter and the mist extractor with evenly distributed flow is the Leff. The seem
to seam length may be estimated as the larger of the following:
Lss = Leff +d/12 or Lss = (4/3)Leff for gas capacity
For vessels sized based on a liquid capacity basis Lss = (4/3)Leff
Slenderness ratio
Experience indicated that the ratio of the Lss divided by outside diameter
should be between 3-5
Three-phase Horizontal water oil separator design (cont.)
Horizontal separators sizing other than half full
Gas capacity
84
Liquid capacity
If β is known, α can be determined from chart.
Gas and liquid capacity constraint design constant vs. liquid height of a cylinder for a horizontal separator other than 50% full of liquid ( field units).
85
Three-phase Horizontal water oil separator design (cont.)Settling Equation Constraint
From the maximum oil pad thickness, liquid flow rates, and retention times, a
maximum vessel diameter may be calculated. The fractional cross-sectional area
of the vessel required for water retention may be determined as follows:
where
αl : fractional area of liquids,
αw : fractional area of water.
The fractional height of the vessel required for the water can be determined
by solving the following equation by trial and error:
86
by solving the following equation by trial and error:
where βw, represents the fractional height of water. A maximum vessel diameter may
be determined from the fractional heights of the total liquids and water as follows:
where dmax is the maximum vessel internal diameter in inches. Any vessel diameter
less than this maximum may be used to separate specified water droplet size in the
specified oil retention time.
Three-phase vertical water oil separator design
By setting the gas velocity equal to the terminal droplet, the following
may be derived:
Settling water droplets from oil phase
Gas capacity
The requirement for settling water droplets from the oil requires that the
following equation must be satisfied:
87
following equation must be satisfied:
for dm=500 micron SG
Qd oo
∆=
µ0267.02
Three-phase vertical water oil separator design (cont.)
Settling oil droplets from water phase
SG
Qd oo
∆=
µ167.02
For 200 micron droplets
Retention time constraint
From two-phase separator design:
88
In vertical separators whose sizing is liquid dominated, it is common to choose slenderness ratios no greater than 4 To keep the height of the liquid collection section to a reasonable level. Choices between 1.5 to 3 are common, although height restrictions may force the choice of a lower slenderness ratio.
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