5

Surface Production OperationsENPE 505

1

ENPE 505Lecture Notes #5

Separation SystemsHassan Hassanzadeh

EN [email protected]

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.


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.

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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


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


An "arch" plate type mist extractorvane-type mist extractor made from angle iron

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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.


3-10 micron in diameter liquid droplets

wire-mesh mist extractor

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Dimensions for the placement of a wire-mesh mist extractor.[ H represents

minimum height, and H, must be at least 1 foot (305mm).]


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.

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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.


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


( ) 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


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


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


, ,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

http://maintenanceengineering.in www.weamco.com

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


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


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:


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.



( ) ( )

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


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:


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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