(process) separators
TRANSCRIPT
زی و بهره برداری صنایع نفت (ایکو ) شرکت راه اندا Common course
(process)
Separators
موزش، تحقیق و توسعوآمدیریت 1391شهریور
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Objectives: Upon completion of the unit the trainees should be able to:
Explain the classification, flow patterns, internal devices of separators commonly used in oil
industries.
Understand principals of separation.
Understand the application of separators.
Understand important parameters of operation and troubleshooting.
Contents:
1. Description of separators.
2. Design of separators.
3. Application.
4. Operation.
5. Troubleshooting.
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SEPARATORS
INTRODUCTION
A separator is a vessel in which a mixture of fluids that are not soluble in each other are
segregated from one another. In the oilfield, separators are used to segregate gas from
liquid; or one liquid such as condensate from another liquid, such as water.
There are more separators in oil and gas process facilities than any other type of other
process equipment. Sometimes they are called scrubbers, accumulators, flash tanks, or
other names. Regardless of what the vessel is called its function is to segregate 2 or more
fluids … usually gas and liquid; and the operating procedures are the same.
Production Separators On Offshore Platform
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1- DESCRIPTION OF SEPARATORS
A – Classification
Separators are classified in two ways : the position or shape of the vessel, and the number
of fluids to be segregated. Two vessel shapes are commonly used:
1. Horizontal
2. Vertical
The number of fluids to be segregated is usually two or three. If there are two fluids, such
as gas and liquid, the separator is referred to as a 2-phase type, if three fluids are
segregated, such as gas, oil and water, the vessel is a 3-phase type. The number of phases
refers to the number of streams that leave the vessel and not the number of phases that are
in the inlet stream.
For example, well stream separators frequently have gas, oil and water in the inlet stream,
but only gas and liquid are segregated in the vessel. The liquid flows to another separator,
where oil and water are segregated. Consequently, a 2-phase separator is one in which the
inlet stream is divided into two fluids, and a 3-phase will have three products.
Each of the vessel shapes can be either 2-phase or 3-phase. In other words, we can have a
horizontal 2-phase, a horizontal 3-phase, a vertical 2-phase, and so on (Figures 1 –5).
Some well streams contain sand or other solid particles which are removed in a separator.
Special internal devices are provided to collect and dispose of solid materials. They are not
considered another fluid phase in the classification of the vessel.
Horizontal wellhead separator
B – Flow Patterns
The flow in horizontal or vertical separators is similar for 2-phase separators : the mixture
enters the side or end, the lighter fluid (usually gas) passes out the top, and the heavier
fluid is withdrawn at the bottom.
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Figure 1
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Figure 2
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Figure 3
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Figure 4
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Flow in a centrifugal separator, such as that shown in Figure 5, is somewhat different than
that in conventional types. The vessels are usually vertical and depend on centrifugal
action to segregate the fluids. The inlet is directed to flow around the wall of vessel or
inside a centrifugal element in a swing motion. The heavier liquid moves to the outside,
Figure 5
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and drops collect on the wall and fall on the bottom. The lighter fluids collect in the middle
of the vessel and flow up the outlet pipe.
Flow in a 3-phase vessel can be in one of several manners as shown in Figure 6. The 3-
phase inlet stream enters the side; gas flows out the top and liquid settles to bottom. Oil
floats on the water and is withdrawn out the side of the vessel. Water is withdrawn at the
bottom.
This type of liquid collection would be used with water and distillate, where a clean
separation occurs. The disadvantage of the system is that the water level is controlled at
the interface with oil, and if any foam or emulsion is present at that point, it will interfere
with the action of the level control float.
Another method of control in a 3-phase vertical separator is shown in the upper right hand
drawing of Figure 6. In this vessel, the water falls to the bottom of the vessel on the left
side, and flows into the water chamber of the right side, where it is withdrawn with a level
controller. Oil is withdrawn on the left side with a level controller. An emulsion at the oil-
water interface will not interfere with the operation of the level controller on the water or
oil streams. The disadvantage is that the liquid flow path in the vessel is more complex and
the additional internals take up space normally reserved for separation.
Liquid flow in a horizontal separator is usually a variation of one of the two schemes
shown in Figure 6 In the middle drawing, the oil and water settle to the bottom in the left
hand portion of the vessel. The oil layer floats on the water spills over the weir and is
withdrawn with a level controller. The water remains on the left side of the weir and is
withdrawn with a controller. The level control float is subject to problems with emulsion at
the water-oil interface.
The lower drawing in Figure 6 indicates the flow pattern with no interface control. Oil
spills into the bucket and is withdrawn with a level controller. The water flows along the
bottom of the vessel into the chamber on the right, where it is withdrawn.
Centrifugal separators are normally used for gas-liquid separation. They are smaller than
conventional units.
C – Separator Internal Devices.
A wide variety of mechanical devices are used inside a separator to improve its efficiency
and simplify its operation. The most commonly used devices are:
1. Deflector plates (Figure1). A deflector plate is used in gas-liquid separators in front of
the inlet nozzle on the vessel. The plate can be flat or dished. As the inlet stream strikes it,
the fluid falls to the bottom and the gas flows around the plate. In a vertical vessel, the
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deflector may divert the inland stream around the wall of the vessel to create a centrifugal
action.
2. Mist pads (Figures 1 and 3). Mist pads are most frequently used in gas-liquid separators
to remove the mist from the gas. The pad is made mostly of closely woven wire that is 10
to 20 cm [4 to 8 in.] thick. It is held in place by a sturdy grid which prevents it from being
swept out or torn by a sudden surge of gas. Mist pads are also used in oil-water separators
to aid in segregating the two liquids. They can be of value in breaking an emulsion of oil
and water.
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Figure 6
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3. Coalescing plates (Figures 1, 2 and 3 ). Several configurations are available from
different vendors. They are used in some gas-liquid vessels to remove liquid from the gas
these are often called a vane pack.
4. Straightening vanes (Figure 1). These are also used in gas-liquid vessels. They are
used when hydrate or paraffin prevents the use of mist pads.
5. Filter elements (Figure 2 and 4 ). Filters and used to remove solid particles and mist
from gas and oil-water vessels. The separator usually contains a quick-opening closure for
access to allow for replacement of the elements.
6. Coalescing material (Figure 4). Excelsior and hay are the most commonly used
material. In special applications, pellets with coalescing properties are used. The material
must be held in place with a grid or perforated plate. A manhole is usually included on the
vessel to allow replacement of the material. Coalescing material is used in oil-water
separating vessels.
7. Weir (Figure 2). Its function has been described.
8. Centrifugal devices (Figures 1 and 3). These are used in gas-liquid separators. They
impart a swirling action to the inlet stream that concentrates the liquid phase on the outer
wall of the device.
9. Horizontal baffles (Figure 1). These are used in gas-liquid separators to prevent waves
in the liquid phase. They are usually located near the liquid level in the vessel.
10. Vortex breakers (Figure 1). There are used on all separators on the liquid draw off
nozzle to prevent a vortex from forming, Which would allow some gas to flow out the
liquid line.
11. Float shield (Figure 3). This device is used when an internal float is used to control the
liquid level. It prevents the float from flopping around from wave action in the liquid.
12. Water jets (Figure 7). Water jets are sometimes called sand jets. Their purpose is to
spray the sides and bottom of the vessel with a high pressure stream of water or other
liquid to fluidize sand or other solid particles so they can be drained from the bottom.
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13. Sand cones (Figure 7). These are used in vessels that have a continual flow of sand or
other solid particles. The solids collect in the cone, and are periodically flushed out. Water
jets are usually included with the cones.
Figure 7
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D - Construction and Vessel Codes
Most separators operate under pressure. They are usually made of steel and built in
accordance with rigid pressure vessel specifications. The heads and shell are usually made
of steel, and all seams are welded. If server corrosion is anticipated, the separator may be
lined with a corrosion resistant material such as monel or stainless steel. If salt water is the
corrosive agent, protection can be provided with a coating or special paint or tar.
Most internals are also made of steel and welded to the wall or head of the vessel. If man
ways are provided, the internals may be bolted in place so they can be removed for
cleaning or repair.
Virtually all pressure vessels used in the hydrocarbon industry are constructed in
accordance with the applicable pressure vessel code. The code provisions dictate the
mechanical construction of the vessel, e.g. wall thickness, welding techniques, nozzle
reinforcement, etc. The vessel sizing criteria is set by factors to be discussed in the
following section.
The pressure vessel code used in the U.S. is the ASME pressure vessel code, section III,
division I. In the U.K. the code is the BS 5500.
For a process engineer, perhaps the most important specifications are the wall thickness
equations. These allow calculation of:
1. Design wall thickness which can be used to estimate vessel weight, cost and lifting
requirements.
2. MAWP of vessel in-service which has experienced metal loss due to corrosion, erosion,
or mechanical damage.
For the ASME code,
0.6tR
SEP
0.6PSE
PRt
Where:
t = wall thickness, in.
P = design pressure, psig
R = internal radius of vessel, in.
S = maximum allowable stress value of steel, psi
E = joint efficiency of welds
A number of commercial steels are used for vessel construction.
2- DESIGN OF SEPARATORS
A – Principles of Separation
Two factors are necessary for separators to function:
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1. The fluids to be segregated must be insoluble to each other.
2. One fluid must be lighter than the other.
Separators depend upon the effect of gravity to segregate the fluids. If the fluids are
soluble in each other, no separation is possible by gravity alone. For example, a mixture of
distillate and crude oil will not separate in a vessel because they dissolve in each other.
They must be separated in a distillation process.
Since a separator depends on gravity to segregate the fluids, the ease which two fluids can
be segregated depends upon the weight of the fluids. Gas usually weighs about 5% as
much as oil, and the two will separate in a few seconds. On the other hand, oil may weigh
only three-fourths as much as water, and separation may take several minutes. The primary
factor that affects separation is that of the difference in the weights of the fluids.
You recall the density of a fluid is the weight of 1 cubic meter [1cubic foot] of the
material. Water has the density of 1000 kg/m3 [62.4 Ib/ft
3]. Crude oil density is about 800
kg/m3 [50 Ib/ft
3]. The density of gas will depend primarily upon its pressure. The density
of 1 m3 of natural gas at 5200 kPa pressure is about 36 kg/m
3 [density of 1 ft
3 of natural
gas at 750 psia is about 2.25 Ib/ft3]; but at 102 kPa [15 psia], density of gas is only 1.6
kg/m3 [0.1 Ib/ft
3].
It would appear gas having a density of 36 kg/m3 [2.25 Ib/ft
3] would instantly separate
from crude oil that weighs 800 kg/m3 [50 Ib/ft
3]. About 95% separation will occur almost
instantly. However, some liquid will remain in the gas in a fine mist, and it must settle out
for separation to be complete. If mist is not removed from the gas in the separator, it will
eventually settle out in the gas flow lines-possibly in a burner-and could cause serious
problems.
A common example of coalescing occurs when water drops form on the windshield of a
car as it is driven in a fog. As the tiny water drops, which make up the fog, strike the
windshield, they combine with other drops and eventually form a drop large enough to run
down the glass.
The first 6 internal devices listed previously are all forms of coalescers. In each device,
liquid drops adhere to the device and combine with other drops until a large drop forms
that will fall out. The effectiveness of separation will depend upon the amount of
coalescing area that is present.
In order to understand the way separation takes place, we will concern ourselves with
segregating a mixture of gas and oil into its components. As we mentioned, the ease with
which two fluids will separate depends upon the difference in weight of the two fluids. The
greater the difference in weight, the easier the separation.
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In the process of segregating gas from liquid, we actually have two separate stages:
1. Separate liquid mist from the gas phase.
2. Separate gas in the form of foam or froth from the liquid.
Droplet of liquid mist will settle out from gas, provided:
1. The gas remains in the separator long enough for the mist to drop out.
2. The flow of the gas through the separator is slow enough so that no turbulence occurs
which will keep the gas stream stirred up and prevent liquid from setting out.
The difference in weight of gas and liquid will determine the maximum flow rate of gas
that will allow the liquid to settle out. For example, most of the mist droplets will drop out
of gas at 5200 kPa [750 psia] as long as the gas is moving in the separator less than 30
cm/s [1 ft/sec]. In other words we make the separator large enough so that the gas travels
from the inlet nozzle to the outlet nozzle at a rate of 30 cm/s [1ft/sec] or less.
We said that gas at 5200 kPa [750 psia] weighed about 36 kg/m3 [2.25 Ib/ft
3], whereas, it
weighed only 1.6 kg/m3 [0.1 Ib/ft
3] at 102 kPa [15 psia]. Since its density is lower at 102
kPa [15psia], the oil droplets will settle out faster because there is a greater difference in
weight between low pressure gas and oil. Consequently, the gas can flow faster in a low
pressure separator. In fact, it can flow at 152 cm/s [5 ft/sec] and not interfere with liquid
droplets as they fall out.
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Gas bubbles in the liquid will break out of the liquid in most oil field applications in 30 to
60 seconds. The length of time the liquid remains in the vessel is called its residence time.
If we want a liquid to have a residence time of 60 seconds, and the inlet flow rate is 380
L/min [100 gpm], we make the liquid portion of the vessel large enough to hold 380 L
[100 gal] for one minute.
If the gas does not break out of the liquid in the separator, it will eventually come out in
the storage tank somewhere, and will require costly recompression to boost pressure back
up to that in the separator.
Another reason the gas and liquid steam leaving the separator must be pure is that the
presence of one in the other will make accurate flow measurements impossible. When
liquid contains gas bubbles, the volume of the mixture is increased by the volume of the
gas in it. Liquid mist in gas will also cause the flow measurement to read high.
B – Design of Separators
Separators are designed in two steps:
1. Determine the size of the vapor section in which liquid droplets will settle out.
2. Determine the size of the liquid section in which gas bubbles will break out.
The size of the vapor section is determined by first calculating the velocity of gas in the
vessel. From knowledge of the gas flow rate we can then calculate the area needed for
vapor flow and the diameter.
For oil gas separators, the gas velocity can be calculated from equation 1.
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0.5
V
VLS
KV
ρ
ρρ
Where:
V = maximum allowable vapor velocity, m/s (ft/sec)
Ks = Separator sizing parameter m/s [ft/sec]
L = Liquid density, kg/m3 [Ibm/ft
3]
V = Vapor density, kg/m3 [lbm/ft
3]
Typical separator sizing parameters are shown below:
Ks
m/s ft/sec
Vertical 0.05 - 0.10 0.16 - 0.34
Horizontal 0.12 - 0.15 0.40 - 0.50
Most oil companies size the vapor portion of the separators using a Ks value within the
ranges shown above. The allowable gas velocity in horizontal separators is higher than in
vertical separators because there is less interference between the gas velocity and the
gravitational force acting on the droplet. A typical production/process separator is
designed to remove most of the droplets 150 m and larger by gravity. Small droplets
(down to about 30m) are removed in the mist extractor. Many of the droplets smaller
than 30 m are not removed from the gas carry over into the downstream equipment. This
is not usually a serious problem but can be troublesome in some instances. Examples
include systems where the downstream equipment includes glycol dehydrators, mol sieve
dehydrators or reciprocating compressors. In these cases an additional “high efficiency”
separator such as a filter separator or cyclone type is installed.
Once the allowable velocity in the vapor section has been determined, the area for vapor
flow is calculated from the equations below:
A = qa/V = /4 d2
2
VF V
a4qd
2a
Where:
A = area available for vapor flow, m2 [ft
2]
q = actual vapor flow rate, m3/s [ft
3/sec]
V = allowable vapor velocity, m/s [ft/sec]
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d = vessel diameter, m [ft]
= 3.1416
Fv = correction factor for horizontal separator
The actual flow rate, qa, can be calculated from the standard flow rate qs from the equation:
Z Ts
T
P
sP
400 86
sqaq
Where:
qs = standard flow rate, std m3/d [scf/d]
Ps = standard pressure (usually 101.3 kPa or 14.7 psia)
P = actual separator pressure, kPa [psia]
T = actual separator temperature, K [R]
Ts = standard temperature (usually 288 k, 520R)
Z = gas compressibility factor.
For horizontal separators, liquid occupies part of the vessel cross-section so the liquid level
affects the vapor flow rate. In order to determine the actual vessel diameter the area
calculated in equation 2 must be divided by a correction factor Fv which corrects for the
liquid in the vessel. Fv may be estimated from Figure 8.
Figure 8
Example: Calculate the diameter of the vessel required to separate a 0.8 sp. gr. oil from a
0.65 sp. gr. natural gas at 6000 kPa [870 psia] and 40C [104F]. The gas compressibility
factor is 0.86 and the gas flow rate is 2.0 std m3/d [70 MMscf/d].
SI:Gas density 3Kg/m 50.5
14)(313)(0.86)(8.3
(0.65)(6000)(29)
ZRT
(P)(MW)v ρ
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Liquid density, L = (1000)() = (1000)(0.8) = 800 kg/m3
For a vertical separator, Ks = 0.06 m/s
0.23m/s
0.5
50.5
50.58000.06
0.5
V
VLsK v velocity, gas Allow able
ρ
ρρ
For a horizontal separator, Ks = 0.12 m/s, v = 0.46 m/s
Calculate actual gas flow rate,
/s3
0.365m0.86 2888
313
6000
101.3
400 86
000 000 2aq
Calculate diameter-vertical separator (Fv = 1.0),
56in. 1.42m6)(0.63)(3.14)(0.4
(4)(0.365)
Fv Vπ
a4qd
Horizontal separator (assume hL/d =0.43)
[50in.] 1.26m3)(1.0)(3.14)(0.2
(4)(0.365)a4qd
Fv Vπ
English:Gas density, 3/ftmIb 3.15
73)(564)(0.86)(10.
0.65)(870)(29)(
vρ
Liquid density, L = (62.4)(0.8) = 49.92
For a vertical separator KS = 0.20 ft/s. Allowable gas velocity.
ft/s 0.76
0.5
3.15
3.1549.92 0.20
0.5
Vρ
Vρ
Lρ
sKv
For a horizontal separator, Ks = 0.40 ft/s, v = 1.5 ft/s
Calculate actual gas flow rate,
/s3
ft 12.770.86870
564
870
14.7
86400
000 000 70aq
Calculate diameter-vertical separator (Fv =1.0),
ft 4.66)(0.63)(3.14)(0.7
(4)(12.77)
Fv Vπ
aq 4d
Horizontal separator (Fv= 0.63), ft 4.1)(0.63)(3.14)(1.5
(4)(12.77)
Fv vπ
a4qd
Once we have found the area needed for vapor flow we must determine the size of the
liquid handling portion of the vessel. For gas-oil separation, the required residence time in
the liquid is 2-3 min-to prevent carry under of gas bubbles (blow-by). The liquid holding
volume is equal to the liquid rate multiplied by the retention time
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1440
tL
qV
Where:
V = liquid volume, m3 [ft
3]
qL = liquid rate, m3/d [ft
3/d]
t = retention time, min
Once the liquid volume has been calculated, it is an easy matter to calculate the total vessel
height required to separate the liquid and vapor. This is illustrated in the following
example.
Example: Estimate the height of the vertical separator in the previous example if the
oil-gas ratio in the separator is 981 m3/m
3 [5000 scf/bbl].
SI:liquid rate = (20 000 000/891) = 2245 m3/d
For a retention time of 2 min, 3m 3.1
1440
(2245)(2)V
The diameter of the vessel is 1.22 m, so the vertical height required to hold the liquid
(ignore the head) is
1.96m2
2)(3.14)(1.4
(4)(3.1)
2d π
v 4L
The vapor disengaging space above the liquid level is usually 1.5 to 2 times the vessel
diameter. If we use the factor 2 in this case, the vapor disengaging space is
(1.42)(2) = 2.84m
Total vessel height = 2.84 + 1.96 = 4.8m
Additional height may be required for slugging or surging flows or for
operator response.
English: liquid rate = (70 000 000/5000) = 14 000 BPD
For a retention time of 2 min
3109ftbbl 1
1440
(14000)(2)V 4.9
ft 6.62
)(3.14)(4.6
(4)(109)
2d π
(4)(V)L
Vapor disengaging space = (2)(4.6) = 9.2 ft
Total height = 6.6 + 9.2 = 15.8 ft
For horizontal separators the liquid retention calculation is required to determine the
normal liquid level in the vessel. The vapor capacity is then rechecked after Fv can be
determined and the calculation proceeds until a properly sized separator can be found.
Most horizontal separators have an L/D ratio of 3:1 to 5:1, with higher pressure vessels
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using the higher L/D. Let’s check the size of the horizontal separator using the previous
example. Assume L/D = 5:1.
If we ignore vessel heads, the liquid contained in the horizontal separator is:
32.9m0.376.3
21.26
4
3.14
LLF
2d
4
π
LV
3100ft0.3720.5
24.1
4
3.14
so at (hL/d) = 0.4 the vessel has nearly adequate liquid capacity and the calculated
separator size of 1.26 m is OK!
Horizontal separators are generally preferred in crude oil separation because the extra
cross-sectional area makes 3-phase separation easier and allows more time to destabilize
foam. Compare the cross-sectional area in the vertical separator A = 1.6 m2 [17.2 ft
2] to
that in the horizontal separator A = 5.7 m2 [61.4 ft
2].
Figure 9a and 9b provide an easy solution to estimate the diameter of horizontal
separators. Once the vapor disengaging area and liquid residence volume have been
calculated it is easy to enter the table and determine the vessel size.
Example: Using the numbers from the previous example estimate the required vessel
size for the horizontal separator.
SI:A = q/v = 0.365/0.46 = 0.79 m2 VL = 3.1 m
3
From Figure 9a, d = 1.3m
English:A = q/v = 12.77/1.5 = 8.5 ft2 VL = 19.4 bbl
From Figure 9b, d = 54 in.
The procedures presented for sizing separators are for estimating purposes only. An actual
design would take into account slugging, surging, control philosophy and other factors.
However, they can be used in checking the size of separators in your plant. If you check
the size of separators in your plant and find one or more that appears too small, you should
bring it to the attention of your supervisor so that the size can be accurately determined.
In the example used for sizing separators, we assumed that only gas and oil were present in
the vessel. If water had been present, we would have taken it into consideration in sizing
the liquid section of the vessel. The liquid section would have to be large enough to
provide the residence time for both the oil and water. This will be discussed later.
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Figure 9a
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Figure 9b
One other point: Even though water is present, the vapor disengaging area is based on the
difference in gravity of the gas and oil, and not the gas and water. Water is heavier than oil
and, consequently, it will separate faster from gas than oil will. Since it is more difficult to
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separate gas from oil, we design the vessel on this basis, and the water will drop out before
the oil does.
C – Selection of Separator Internals
Internal devices are used in separators to speed up the separation process to reduce the size
and cost of the separator. Proper selection of internals can reduce the cost of a separator as
much as 50%.
Most of the internal devices are installed in the vapor section to remove liquid droplets
from the gas. The separator sizing procedures are based on separators containing a mist
pad only. The diameter will increase approximately 20% if there is no pad or other
coalescing device in the vapor section.
Selection of internal devices will depend upon the composition and quality of the stream
entering the separator. Coalescing devices should not be installed if there is a likelihood
they will become plugged with wax, sand, hydrate or other corrosive products. A stainless
steel mist pad can be installed in a corrosive gas stream without danger of becoming
plugged with corrosive products. However, coalescing plates, straightening vanes, and
centrifugal devices should not be used when there is a likelihood of fouling from dirt, wax
or hydrate.
Centrifugal devices are highly effective in removing mist from gas as long as the flow of
gas is high enough to maintain a proper velocity in the centrifugal device. These devices
are most effective when the inlet stream is mostly gas flowing at a fairly constant rate.
Vortex breakers should always be installed in each liquid outlet line. Without these
devices, a funneling effect may occur when liquid is withdrawn, and gas will flow out the
funnel with liquid.
An inlet deflector plate is another internal device that can be used in all separators. This
device stops the liquid from entering the separator and prevents it from flowing out the
middle of the vessel and thereby reducing the effectiveness of the vapor disengaging
space.
A float shield should be installed on all separators containing an internal float used to
control level in the vessel. If the float is in an external cage, no protection is required
inside the vessel.
Water jets should be installed if there is a likelihood of an accumulation of sand or dirt in
the bottom of the vessel. These are most frequently used on wellhead separators to remove
sand produced in the well stream.
The following shows the application and limitations on internal devices:
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D – Application of Internal Devices Used in Separators.
Internal device Purpose of devices or situation where devices should not
be used
Mist pad a. remove liquid mist from gas.
b. Break oil-water emulsion
c. Not used where hydrate, wax or dirt may be present
Deflector plate a. separate liquid from gas
b. used in all services
Coalescing plate a. Remove liquid mist from gas
b. Separate oil from water
c. Not used where hydrate, corrosion, wax or dirt may
be present
Straightening Vanes a. Remove liquid mist from gas
b. Separate oil from water
c. Not used where hydrate, corrosion, wax or dirt may
be present
Filter elements a. Remove solid particles from gas or liquid
b. Separate oil from water
c. Remove mist from gas
d. Not used where wax or hydrate may be present
Coalescing materials a. Separate oil from water
b. Not used when wax is present
E – Common Application of Horizontal and Vertical Separators
Type Application
Horizontal 1. High gas-oil ratio streams.
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2. Oil-water segregation where long residence time is required.
Vertical 1. Low gas-oil ratio streams
3. Where a high level of liquid must be held to prevent a pump
from vapor locking, or maintain a liquid seal.
The designation of high or low gas-oil ratio is rather arbitrary. Following are specific
instances in which high or low GOR’s usually occur:
Low Gas-Oil Ratio High Gas-Oil Ratio
1. Oil well streams 1. Gas well streams
2. Flash tanks in dehydration and
sweetening plants
2. Gas pipeline scrubbers
3. Compressor suction scrubbers
3.Fractionators reflux
accumulators
4. Fuel gas scrubbers
The terms flash tank, accumulator and scrubber are commonly used for specific
applications of separators. The vessels are gas-liquid separators.
3. OPERATION
A – Start-Up
1. If the vessel is empty, close a block valve in each liquid outlet line from the vessel to
prevent possible leakage through a control valve in the liquid line.
2. If the vessel has a pressure controller, it should be set at about 75% of the normal
control pressure, and slowly bring it up to a normal pressure after the vessel is in service.
This will prevent pressure relief devices from opening in the event the pressure controller
is out of adjustment and allows the pressure to build up above operating pressure.
3. If the vessel has low level shutdown devices, they must be deactivated or liquid must be
added to the vessel to a point above the low level devices.
4. Check the flow lines out of the vessel to see that each stream leaving the vessel flows in
the proper direction.
5. Slowly open the inlet stream to the vessel.
6. When the liquid level reaches the range of level controllers, place level controllers in
service and open the block valves that were closed in step 1.
7. Adjust level and pressure controllers to stabilize their operation.
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B – Shut-Down
1. Close a valve in the inlet stream.
2a. Close valves in liquid outlet line to prevent liquid from leaking out.
2b. If the vessel must be drained, open the by-pass line on the level control valves, or
adjust the level controllers so the level control valves stay open until the vessel has
drained. Close block valves in the liquid outlet lines after draining.
3. If the vessel must be depressured, close a block valve in the gas outlet line.
4. Depressor the vessel by opening a valve in the line from the vessel to the vent or blow
down system.
5. If possible, leave a small positive pressure on the vessel while it is shutdown to prevent
air from entering so that it will not have to be purged prior to start-up.
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C – Routine Operation
1. Routine operating checks are observing the various level, pressure, temperature and
flow control instruments to see that they are controlling within the proper range.
2. Diaphragm-operated control valves should be stroked occasionally to see that they will
fully open and close without restriction.
3. Gauge glasses should be drained periodically to prevent scale or debris from
accumulating in the lines or gauge valves and causing them to show false levels.
4. If the vessel has filters or coalescing chambers, the pressure drop across them should be
observed for an increase which indicated a build-up of solid particles, and the need to
replace or clean them.
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– Control
Separators have two major control points:
1. Pressure control 2. Level control
each will be discussed separately.
1. Pressure Control
The gas capacity of a separator increases as its operating pressure rises. Increasing the
pressure reduces the actual volume of gas, and thereby lowers the velocity of gas in the
vessel. Pressure is regulated with a pressure controller, which regulates the flow of gas
leaving the vessel. The control valve is often a butterfly valve to minimize pressure losses
across the valve.
Pressure control is sometimes accomplished by sending the pressure control signal directly
to the governor on a compressor. This is a very popular control scheme when the
compressor driver is a variable speed such as a gas turbine.
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2. Level Control
a- 2-phase separators
The point at which you hold the level of liquid in the separator can have a significant
effect on the operation of the vessel, particularly in a horizontal separator. The level of
liquid needs to be high enough so that the volume of liquid in the vessel will provide the
desired residence time for gas bubbles to break out. If the liquid level is too high, the
liquid residence time will be more than is required. This will not affect the quality of the
liquid that is withdrawn from the vessel, but it will reduce the vapor disengaging space and
can result in some liquid carryover in the outlet gas stream.
The liquid level control point in a vertical separator usually will not have much effect on
the quality of the gas out of the vessel, because the vapor space is usually more than 100
cm [39 in.] high, and a change of a few centimeters [inches] will have little effect.
However, on a horizontal separator, a small change in the liquid level can have a
significant effect on the vapor disengaging space, particularly on a small diameter vessel.
From the above you can see that changing the level 8cm [3 in.], changes the volume of
vapor space by 20%. The change would be less in a larger diameter vessel.
The point at which the level controller should be set will depend upon the flow rates of
liquid and gas entering the vessel. If the gas rate is above design, and the liquid rate is less,
you should run with a lower level to allow more room in the vessel for vapor disengaging.
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On the other hand, if the liquid rate is up, and the gas rate is down, you should raise the
level in order to provide more liquid residence time.
Effect of 8cm [3 in.] change in 96 cm [38 in.] Diameter horizontal separator on
volumes of liquid and gas in vessel
It is often difficult to determine whether the liquid residence time is sufficient to allow gas
bubbles to break out. If it is dumping into an atmospheric tank, you might get some idea of
its gas contact by observing the amount of gas that is being vented from the tank.
If the gas leaving a separator flows to another process vessel, then liquid carryover will
usually fall out in it. If liquid carryover is noticed, it often can be stopped by lowering the
liquid level. Generally, liquid carryover in the gas stream will cause more operating
problems than gas bubbles in the liquid stream. Consequently, it is usually better to hold
the liquid level on the low side rather than the high side in horizontal separators.
This is a good place to pause for a minute and discuss level controllers. Most level
controllers use an external cage with displacer element. The displacer element senses the
buoyant force of the fluid in the cage and transmits the signal to the controller via a torque
tube. When the level in the separator rises, the level controller senses the rise and signals
the control valve in the liquid outlet line to open to allow more liquid to flow out.
Conversely, when the level drops, the level controller signals the control valve to close.
Most level controllers will hold a constant level inside the separator as long as the flow of
liquid is fairly constant. However, if the flow of liquid increases, the level of separator will
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rise and remain at the higher point until the flow rate drops, or until the level set point in
the controller is lowered. The amount of offset depends on the proportional band (gain) of
the controller. Most level controllers use narrow proportional band settings so the offset is
minimal.
If a level controller is equipped with reset, the controller will hold a constant level inside
the separator when there is a change in the liquid flow rate leaving the vessel. However,
most oilfield level controllers do not use a reset, and the level will change each time there
is a change in flow rate.
b. 3-phase separator level control
A 3-phase separator is one in which the outlet streams are gas and two liquids. In almost
every 3-phase separator, one of the liquids is oil; the other one is usually water, but it may
be glycol, brine, amine, or any other liquid that is not soluble in oil. For our discussion, we
will assume they are oil and water. The operating principles will be the same for any two
liquids that are not soluble in each other.
The term water cut is used in the oilfield to denote the percentage to total liquid that is
water. A 20% water cut would be 20% water and 80% water and 80% oil. A low water cut
usually means less than 10% water; a high water cut is more than 50%.
Level control in separators making water and oil is little more involved because control of
the water level will affect the residence time of both the water and oil. Furthermore, these
vessels are often in a service in which the quantities of water and oil change drastically
during the operation of the separator.
For example, a new oil well might make 7000 m3/d of gas, 40 m
3/d of oil and 1m
3/d water
[250 Mcf/d of gas, 250 bbl/d of oil and 6 bbl/d of water]. After five years the production
may change to 11000 m3/d of gas, 30 m
3/d of oil and 15 m
3/d of water [400 Mcf/d of gas,
200 bbl/d of oil and 100 bbl/d of water]. During the early stages of production, most of the
liquid section is filled with oil. The water level is operated near its lowest control point.
After 5 years, the water level must be raised in order to provide sufficient residence time
for the higher water production.
Control of the water level in the above case was accomplished with a level controller
having its displacer element partially immersed in water and the remainder in oil. The
displacer element that is used on the controller must be designed for the difference in
density of the oil and water that are in the vessel. A float used to control the level of oil in
a gas-oil interface would not function in an oil-water interface.
In order to avoid a displacer element at the oil-water interface one of the methods shown
on the following drawing is used.
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In the vertical separator shown below, the oil level is changed by resetting the oil level
controller. In the horizontal separator, the level in the oil setting chamber is fixed by the
height of the weir on the oil bucket. The volume of oil within the bucket is relatively
small, and no significant change in the oil setting volume will result from a change in level
within the bucket.
In most separators, the total liquid setting volume is fairly constant. The percentage of the
total volume that is used for oil and water setting depends upon the location of the
interface. It is determined by the level of water in the water chamber.
The location of the interface is affected by two factors:
1. Difference in density of water and oil.
2. Level of water in the water chamber.
The effect of changing the water level on the interface level is shown on the next page for
an oil having a relative density of 0.75 [an API gravity of 57]. You will see that changing
the water level 1 unit moves the interface level 4 units, and significantly from 76 cm to 79
cm [30 to 31 in.]; the volume of the water setting section increases from 22% to 33%,
which is a 50% increase in volume. The water residence time will increase 50%. The oil
settling volume changes from 78% to 67%, which is a 14% reduction.
The effect of water level on the interface level also applies to vertical separators shown on
the following page.
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The oil-water interface is often difficult to detect. Wood, rags, scale, corrosion products
and dirt that sink in oil but float on water will accumulate at the interface. This material
tends to promote foam or and emulsion of water and oil. Consequently, there may be no
clear-cut interface, but instead, a layer of trash and oil-water emulsion will form between
the oil and water. The mixture will cause erratic action of the level controller.
It is not unusual for a gauge glass to show a distinct interface when this layer is in the
separator. The following illustrates this.
Liquid in gauge glass is clean oil and water. Trash layer in separator does not show in
gauge glass.
If one of the gauge glass connections to the vessel is in the trash layer, the glass may fill
with the material, and an interface cannot be seen. When this occurs, the trash layer should
be drained from the vessel.
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When one gauge glass connection is in trash layer, the entire gauge glass may fill with
trash and no oil-water interface is visible.
If the displacer element on the water level controller is immersed in a layer of trash and
emulsion, it may not be able to distinguish a difference in density between oil and water,
and will not operate properly.
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4- TROUBLESHOOTING
The cause of an operating problem is found by a process of elimination. Each event which
can cause the problem is checked until the culprit is found. The proper sequence for
checking the various causes is to eliminate the easy ones first. These are the instruments:
pressure gauges, control valve positions, controller output pressures, gauge glasses, flow
meters, etc. In making these checks, be sure that the instruments are working properly, and
not giving a false reading. Once the easy causes are checked and eliminated, the more
difficult causes are checked.
A – Troubleshooting procedure for liquid carryover in outlet gas stream
Another important part of troubleshooting is that of maintaining an overall perspective of
the total process, and not just the troublesome equipment. Upsets at front end of a plant
often show up at the back end. Find the source of the problem before attempting to locate
the cause.
TROUBLESHOOTING PROCEDURE FOR LIQUID CARRYOVER IN
OUTLET GAS STREAM
CAUSE OF CARRYOVER TROUBLESHOOTING
PROCEDURE
1. High inlet gas flow rate Check gas flow rate and cut back to
design rate.
2. High liquid level which
cuts down vapor disengaging
space
Check liquid level. Blow down gauge
glass-lower level to design point.
3. Coalescing plates, mist
pad, or centrifugal device is
plugged.
a. check temperature and pressure to
determine if hydrate has formed. Lower
pressure to melt hydrate.
b. measure pressure drop across device.
It should be less than 10 kPa [2psi]. If
pressure drop across mist pad is 0, pad
may have torn or come loose from its
mounting. Pressure drop measurement
should be made at design gas flow rate.
High pressure drop indicates plugging
internally inspect and clean if necessary.
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4. Excessive wave action in
liquid
Install horizontal baffles.
5. Operating pressure is
below design
Check pressure and raise to design or
lower gas rate in proportion to reduction
in pressure.
6. Liquid density is less than
design
Check liquid density. If it is less than
design, gas rate will have to be cut in
proportion to reduction in density.
B – Troubleshooting procedure for inability to hold constant liquid level
CAUSE OF CHANGING
LEVEL
TROUBLESHOOTING
PROCEDURE
1. Float is totally covered
with liquid
a. clean gauge class to get accurate level
reading
b. If float cage is external, drain it to be
sure pipes between cage and vessel are
not plugged.
c. when gauge glass and float cage are
clean, check to see if float is covered
with liquid.
d. Manually drain enough liquid from
vessel so that ½ of float is immersed.
e. Put level controller in service.
2. Liquid level is below float
Note: level controller will not
function if the liquid level is
above or below float. The
float must be partially
immersed in liquid in order
for controller to work.
a. Perform steps a and b above
b. If level is below float, close valve in
liquid outlet line to allow level to rise
until float is ½ covered.
c. Put level controller in service
3. Liquid flow rate has a. If level controller does not have reset,
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changed. the level controller will have to be
changed each time the liquid flow rate
makes a significant change.
b. If the controller has reset, it can be
adjusted to take care of changes in liquid
flow rate.
4. Liquid enters vessel in
slugs. Level controller does
not react fast enough to drain
liquid.
a. Lower set point in level controller.
b. Lower proportional band setting.
c. In some cases it may be helpful to
install a valve positioner on the level
control valve in order for it to open
rapidly.
5. Wave action is causing
internal float to move.
Install float shield.
6. Level control valve is not
operating properly.
a. Check valve action to see that it is not
closing when it is supposed to open.
b. Stroke valve to full open and closed
positions to see that the spring tension is
not too tight or too loose, and that
nothing is under the valve seat to prevent
it from closing.
c. Check liquid flow rate with valve fully
open to see that there is no restriction in
the line.
7. Level controller shows no
response to change in level
a. Manually twist torque tube or float arm
to see that controller shows response. If
there is no response, repair controller. If
controller shows response, float has
apparently dropped off, or liquid level is
above or below float.
b. Check liquid level as described in
items 1 and 2.
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c. Manually open and close drain valve
so that the liquid level travels the full
length of the float. If the controller shows
no response, the float has fallen off.
8. float in oil-water interface
is totally immersed in
emulsion.
a. Check for emulsion in vessel by
draining a line connected to the vessel
near the float.
b. Drain emulsion from vessel if it is
present.
9. Density of oil has changed
so that float will not respond
to change in level .
a. Check density of oil.
b. If it is different from design, consult
level control supplier to get a new float.
The gauge glass that indicates the liquid level is probably the most important operating
device on a separator. It is also one of the easiest devices to plug with dirt and debris, and
cause it to show a false level. Gauge glasses should be cleaned with a brush or with a
chemical solution at frequent intervals; and the gauge valves should be blown down as
required to prevent an accumulation of dirt in them.