Presentation 2009oil and gas

Oil and Gas ProcessingModule B41OA2

Processing SchemesGravity Separators

Sizing MethodsOffshore Applications

Facilities Design

Oil and Gas ProcessingG.White EPS Chemical Engineering Slide 2

Processing Schemes

Objectives

Provide stable environment for processing equipment to operate

Separate well head fluid - gas, oil, water and solids

Meter marketable products Process gas for disposal/export Crude stabilisation

Dispose of non marketable products Treat water for injection/disposal Clean solids


Processing Schemes

Crude stabalisation, export and storage Remove volatile gas components

Meet pipeline export specs - for water, gas, H2S etc

Onshore - Pumping stations for pipeline delivery Buffer tanks

Offshore Export to pipeline to land, sub-sea line to

other platforms Pumping facilities for pipeline delivery Intermediate storage and buffer tanks Offshore - loading to shuttle tankers


Platform Layout: Alba - Level 1

M.Christensen, Chevron UK, IBC Tech. Conf. Nov 1991








Processing Facilities


Processing Facilities

1995 Conoco installed the worlds 1st concrete Tension Legged Platform (TLP) in the Heidrun field in the Norwegian sector.


“TERN” Topside Scheme

G.WhiteHERIOT-WATT UNIVERSITY

DEPT.OF MECHANICAL AND CHEMICAL ENGINEERING

RICCARTON, EDINBURGH. EH14 4AS.

TITLE :NAME :

DATE :DRG/FILE No :

SCALE :Offshore gas, oil and water processingscheme with gas re-injection and

flare disposal10th Feb 1997

LP Gas CompressorIP Gas CompressorHP Gas Compressor

To Flare

To Fuel Gas

Metering

Crude OilCoolers

To Water Treatment

From TERN Field

Crude Oil Export

De-hydratorV-1121

To WaterTreatment

To WaterTreatment

To WaterTreatment

V-1480 V-1111

V-2121V-2221

V-2131V-2231

V-2111V-2211

To Flare

Gas Lift

Crude OilCoolers

P-1401


Processing Scheme for Chevron’s ALBA


Generalised Processing Scheme

Chemical addition to Reduce corrosion Prevent scale Reduce emulsions

Pre Treatment Primary separation

Oil Dehydration

Water Treatment

Gas Treating

Remove Gas Water from oil Solids

Compression Remove water

Remove oil De-gas Re-injection

Choke Valve

Temperature conditioning


Types of Separators

Separators are classified by Pressure rating Low pressure Intermediate pressure High Pressure

Types of operations Bulk Treaters Removing “free water” - Free Water Knock Out Drum Skim Tanks Gas scrubbers - for high gas to liquid ratios


Functions of a Separator

Requirements of a “two phase” oil-gas separator Produce oil free gas - 10 ppm liquid in gas Produce gas free oil Maintain pressure for separation - pressure on gas outlet Maintain pressure inside separator - liquid level control Provision for water separation

Requirements for a “three phase” gas/oil/water separator Produce gas free oil, oil free gas Maintain pressure. Produce oil free from water - typically allow 10% by volume Produce water free from oil Maintain liquid levels for residence times Provide for surges in flow.


Factors Affecting Separation

Gas and liquid flowrates flowrates vary during the field life. Normally peak, minimum and average rates

used for design purposes. Operating Pressures and Temperatures

affect the density and viscosity Slugging of feed streams

upsets in flow causing transient increases/decreases in flowrates Physical properties

compressibility density

Degree of separation specified for the design removing 10 micron liquid drops

Impurities solids, sand, waxes

Tendency for crude to foam Corrosive tendencies.


Two Phase Gas-Liquid Separation Principles

Density difference provides the least effortTime


Three Phase Gas-Liquid Separation Principles

Principle is that the three fluids are left for sufficient time

Gas bubbles rising in heavy and light liquid phaseWater droplets settling in the lighter bulk oil layerOil droplets rising through the heavier bulk water layer.Coalescence of droplets within the dispersion band and with the respective bulk layers

Time

The interface between oil and water may not be clear due to a dispersion band


Separator Sections

Zones inside a horizontal 3 phase separator

Oil OfftakeWater OfftakeSand Offtake

Well Head Feed

Gas Offtake1. Inlet

2. Liquid Profile

3. Liquid from Gas

5. Water from Oil

4. Oil from water


Description of zones

Gas Disengagement - Inlet Distributor Fluid changes direction, liquid forces down. Gas breaks free from liquid

Liquid Profile - Solids Deposition Liquid profile established Solids separate out

Gas-Oil Separation Liquid (oil) drops settle by gravity Mist eliminator removes down to 100m drops.

Oil from Water Separation Oil drops rise due to density difference Coalescence increases drop size Sufficient time allows for process

Water from Oil Separation Water drops fall to o/w interface


Separator Types and Selection Guide

Two common configurations Horizontal Vertical Spherical vessels are also an alternative

Basic Criterion How much solid (sand) is produced:

Buildup of solid material can lead to corrosion, reduction in performance. Regular cleaning by jet-wash system or manual removal.

How steady the flow isSlugging and surges cause increases in feed rates causing levels to increase. Control system needs constant adjusting.

How much water is produced Is any emulsion (dispersion) formed

Long residence time unsuited for primary separators. May need to add chemical de-emulsifier or reduce water quality.

Is foaming a problem


Horizontal Separators

Easy to mount in modular system

Better for foams and emulsions

LT

LT

PT

Gas

Oil

Water

Oil Outlet & level control

Water Outlet & level control

Gas Outlet & pressure control

Well fluid inlet

Inlet deflector dish Weir

Plate

Mist Eliminator

Larger mounting area Poor solids removal Lower surge capacity


Horizontal Separators


Horizontal Separator Module

“Kvaerner” Separator module


Vertical Separators

Liquid level control not so critical for operation

Good for surging flows

Work well for high GOR applications

Difficult for modular systems - transport & installation

Tend to be larger

Access for relief and control valves difficult

Oil

Water

Gas

Inlet Device

Gas

Downcomer

Gas

Oil

Distributor

Water

Inlet


Separator Sizing - The Principles

Oil must be kept inside the vessel to allow• Any water drops in oil pad to sink and coalesce with bulk water layer• Any oil drops to rise and coalesce• Any liquid drops in gas phase to fall

Gas

Oil

Water


Separator Sizing - The Principles

Time for water in oil drop to settle = time to travel effective length

Ug

Us Un

Un

Gas

Oil

Water

Effective Length

Oil Pad


Theoretical Background - Drop Settling Equation

External force causingmotion : Fe

Drag forceopposingmotion : Fd

Buoyancy : Fb

Resolving forces give the acceleration of the particle as :

If the external force is represented by some acceleration term ae say, then:

dbe FFFdt

dum

ee maF

ec

d

b am

F

2

AuCF pc

2pd

d


Settling/Rising Velocity

Under the influence of gravity, particle acceleration is then:

Solving for 0 acceleration gives :

m2

AuCg

dt

du pc2pd

d

cd

dcdp

cdp CA

m)(g2u

This equation cannot be solved directly unless we have an expression for Cd

Laminar Stokes Regime Re

24Cd

Liquid drops in gas phase 34.0Re

3

Re

24Cd

applies for Re<1.0

7.0d Re14.01

Re

24C

applies for 1.0<Re<1000

445.0Cd applies for 1000<Re<200,000


Theoretical Background - Drop Settling Equation

Drag coefficient varies with relative particle velocity – for rigid spheres, we have

0.1

1

10

100

1000

10000

100000

1000000

0.0001 0.01 1 100 10000 1000000 100000000

Particle Reynolds Number

Dra

g C

oeffi

cien

t

Drag Crisis

Stokes

Newton

Intermediate


Settling/Rising Velocity

For spherical drops of diameter dp in the laminar (Stokes) settling region,the drop settling velocity becomes:

For liquids, viscosity correction is used :

18

gdu cd

2p

p

dc

dccd2p

p 3

32 where

18

gdu

If Cd is given as a function of Re, then resort to an iterative process to find Up and Cd:• Set Cd to a value (assume Cd=24/Re)• Calculate Up

• Calculate Re• Calculate Cd from correlation• Calculate Up

Repeat if required

Where subscript d= dispersed phase, c= continuous phase


Situation(3) K m/sGeneral Value 0.1000

In GeneralWith a mist eliminator 0.12 - 0.185

Without 0.075 - 0.15

Gas Phase Settling Equation

To avoid issues with drag equations. for liquid drops in gas phase, maximum gas velocity is given by : Souder’s-Brown Equation

Allowable Velocities

K is a constant depending if the separator is fitted with a mist eliminator or not:

Knock-Out Drum Vertical <0.07 m/sHorizontal <0.1 m/s

Demister Vertical <0.105 m/sHorizontal <0.15 m/s

g

gls Ku


Retention Times

Retention times give the minimum time liquid must be held in the separator.

Accounting for the geometry, fill depth and shape of the separator, equations using retention time have a form similar to :

where o,w = subscripts referring to oil and waterD = Vessel diameterLeff = Effective length for separationQ = Volumetric flowratetr = retention time = constant depending on vessel orientation and unit system

wroreff

2 QtQtLD

Flowrate Volumetric

volume up Holdt r

Retention equations can apply to• 2 phase vessels - hold up the oil until gas is removed or liquid is removed

from gas.• 3 phase - separate oil from water, water from oil, liquid from gas.


Estimating size of droplets of liquid-in-gas or liquid-in-liquid is difficult. Measurement techniques are difficult to implement on-line.

Gas-Liquid Separation

In general, field experience suggests that section should be designed to remove 100m drops. This will prevent flooding of the mist eliminator. Mist eliminators can remove 99% of liquid-in-gas drops between 10 m to 100 m.

Special Cases Gas-Scrubbers (Vertical 2 phase separators used in gas compression trains), are

typically sized for 500 m drops.

Flare or Vent Scrubbers (used to prevent slugs of liquid reaching the flare stack), are designed to remove drops between 300 m to 500 m. Note - mist eliminators are not used here for fear of blockage.

Drop sizes


Liquid-Liquid Separation

Size of water drops inside production separators is difficult to predict.

Water in Oil Drops

Experience suggests equations should be applied for 500 m water-in-oil drops. If separator is sized for 500 m, oil from separator will contain less than 5%-10% water.

Oil in Water Drops

Separation of oil drops from water is easier than water from oil due to higher oil viscosity. Should separator be sized for water removal from oil, water from 3 phase separators can be expected to contain 2000 mg/l oil-in-water.

Drop sizes


Retention Times

Field and laboratory tests can determine retention times easier than measuring drop sizes.

Gas-Liquid Separation

Retention (or residence time) for most 2 phase operations is between 30 seconds and 3 minutes. For foaming crudes, residence times are increased by factor of 4.

Liquid-Liquid Separation

For both water-in-oil and oil-in-water, typical retention times vary between 3 minutes to 30 minutes. For design purposes used:

Onshore 10 minutes Offshore 3-4 minutes

The longer the retention time The larger the vessel The heavier the module Greater the cost


Residence Time Distribution

Perfect “plug flow” will not occur inside separators and a RTD (Residence Time Distribution) profile will be obtained

0

0.002

0.004

0.006

0.008

0.01

0.012

0.014

0.016

0 100 200 300 400 500 600

Time (sec)

No

rma

lise

d D

istr

ibu

tio

n "

E"

Cu

rve

48

32

20

15


Useful Expressions & Terms

Standard Conditions

For oil use, this is 60°F, 14.7 psia (15.5°C, 1 atm) - best to confirm this is true.

Density

Liquid density is quoted as sg (specific gravity with reference to water), or commonly °API

Gas specific gravity is with reference to air at standard conditions

for different temperatures and pressures, use compressibility factors

API5.131

5.141sg

5.131

sg

5.141API

MWZRT

P

29

Gas of Mass Molarsg

ZRTPv



Typical densities of common “crude” oils

Gas Flowrates

Gas volumetric flowrates are quoted at standard conditions:

Conversion to separator conditions requires the density

86400

QQ ss

day

ft10xmmscfdQ

36

s

Type of Oil s.g. oAPIBitumen > 1 < 10

Heavy Oil 1 to 0.93 10 to 20Intermediate Oil 0.93 to 0.83 20 to 40

Light Oil < 0.83 > 40



Liquid Flowrate

bpd 1 US barrel of oil = 0.15899 m3

A STB (Stock Tank Barrel) volume measure is also used - volume of liquid at standard conditions

Producing Gas-Oil Ratio (GOR)

GOR is the volume of gas produced per unit volume of oil produced at standard conditions. The units for GOR are scf/STB or sm3gas/sm3oil.

BS&W - Base Sediment and Water - the non oil fraction of liquid found in oil from separation stages

Water Cut - Represents water content of well head fluid. Typically 10-20% but can rise to 80% as production life increases.


Area Chart

Quick method for areas of segments Geometry of a Circle for areas of segments and sectors

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00 1.10

Depth H / Radius R

Se

gm

en

t A

rea

/R2

Depth

Segment Area

Radius R


Other Expressions

Other features which may occur include:

Drop Size Distribution

Drop formation due to shearing is based on a critical Weber number

Which is used to predict mean drop diameters

Dispersed Phase (for liquid/liquid decanters)

Dispersed phase is a function of density

c2DV

We

c

3l

2DNWe

6.032 We47.41081.0D

d

3.0

h

h

l

l

h

l

Q

QX


Other Expressions

Dispersion Band Thickness

Depth of the dispersion band is a function of flow rate and interfacial area between settling phases:

Qc = Continuous phase flowrate

Al = surface area for contact

n=2.5 to 7

Perforated Plate Distributors

Horizontal decanters use two close mounted perforated plates

Upstream plate - open flow area between 3-10% of separator cross-sectional area

Downstream plate - 20 to 50% “of separator cross-section”

n

cD Al

QkH


Other Expressions

Outlet/Inlet Pipe Velocities

For sizing inlet and outlet pipes, a momentum or velocity limit is used

Example

Bend should be more than 5 pipe diameters before separator

Restrictions on velocities may be due to potential erosion problems

22 kg/ms 1500u

s/m15U


LZA(HH) - High level trip0.15m below inlet or 0.05D

LA(H) - High level pre-alarm

LA(L) - Low level pre-alarm

LZA(LL) - Low level trip

0.1m below LZA(HH) or60 sec flow for control room5 mins for outside action

0.1m below LA(L) or60 sec flow for control room5 mins for outside action

0.36m below LA(H) or2 - 4 mins of residence timeand allow for slugging

Level Control Settings

Level control positions give a degree of flexibility to separator design Response times from control room or outside operation Slugging volumes Residence times

Oil

Water

Gas



Internal liquid level sensors are used to control separator – liquid level measures hold up volume.

Usually 4 recognised level locations –

h1

h2

h3

NLL

LAH

LSDH

Inlet Centrelined

D

h4

h5

LAL

LSDL

h1

h2

h3

NLL

LAH

LSDH

Inlet Centrelined

D

h1

h2

h3

NLL

LAH

LSDH

Inlet Centreline

h1

h2

h3

NLL

LAH

LSDH

Inlet Centrelined

D

h4

h5

LAL

LSDL

h6



For vertical vessels, there are additional considerations which give the distance from the liquid surface to the inlet deflector and to the mist eliminator pad.

NLL

Inlet DeviceFluid Inlet

LAL

LSDL

LAH

LSDH

h

ha

hb

hd

hc

d

D

hss

NLL

Inlet DeviceFluid Inlet

LAL

LSDL

LAH

LSDH

h

ha

hb

hd

hc

d

D

hss


Sizing calculations to find the physical dimensions follow the same path

Specify the inlet velocity using a momentum limit or some maximum value. This gives the size of the inlet pipe.

Set the outlet velocity and hence the outlet pipe sizes

Calculate the maximum allowable gas velocity at peak flowrates from Souder’s Brown equation or recommended limits

Calculate minimum area for gas flow. Actual vessel may have larger gas area e.g. 50% full of liquid

Calculate liquid capacity based on drop settling or residence time

Calculate separator dimensions till size matches L/D constraints (3.5 to 5)

Remember

Production profiles vary over field life

Oversizing can lead to extra costs

Separator Sizing Methods


Sizing Methods - Horizontal 2 Phase

1. Gas Capacity - gives the maximum possible velocity for gas stream

2. Minimum area for flow

3. Liquid Capacity - for surging allow 2x hold up volume

4. Fix gas/liquid interface - Either assume vessel is half full, or write expression for DL in terms of slenderness ratio and liquid fill factor

g

gl

g Ku

g

g

g u

QA

Q=V/tr



Useful Procedure is to :

• Set % area occupied by liquid - Typically 50% or even 75%. Minimum area for gas flow is 12% of total csa

• Calculate length and diameter

• Check Slenderness ratio L/D=3.5

• Set new % area for liquid and repeat.

Note :

• Allow for control levels - e.g. High-High trip, High Alarm

• Effective length = 75% of seam-seam length



More difficult to find since there’s several constraints. Method follows that for 2 phase, with added complication of water from oil separation.

1. Gas Capacity - Souder’s Brown equation

2. Minimum area for gas flow

3. Water drop settling velocity

4. Set axial velocity of oil and water layers based on drop settling velocity

5. Check this should be <0.08 m/s

dc

dccd

2

p

p 3

32 where

18

gdu

g

gl

g Ku

s/m08.0u,u15u npn

1ud

Rec

ppd

drop



6. Calculate areas occupied by oil and water: Use velocities un. Assume un in oil=un in water ( this ensures residence times in both phases is the same.

7. Set the % area occupied by gas: Base this on either calculated minimum area. Better still, use calculated area for liquid flow since liquid is usually a constraint.

8. Find the overall diameter. Calculate total area from 7, then the diameter

9. Locate the gas/oil and oil/water interfaces using geometric considerations: Use geometric chart or equations in Perry to match occupied area with distance from circumference.

10. Using the oil layer thickness, calculate the overall length

11 Check the slenderness ratio: L/D range typically 3.5, maximum 6

12. Check the residence times. Typically 3 minutes, may be more depending on crude

n

p

eff

o

u

u

L

h


Sizing Methods - Horizontal 3 Phase (Cont)

Special Considerations

Turbulence

Reduce settling velocity by some factor to account for turbulence

Axial Velocity

A low settling velocity implies length to oil pad thickness is in ratio of 15:1

Who sets the 15xUp limits ?

Slugging

Allow for increased hold up volumes - could increase size/costs

Internals can decrease length through enhanced separation.

Momentum limits for inlets and offtakes


Sizing Methods Vertical 2 Phase

Calculate Gas Capacity

Souder’s Brown

Find minimum gas/vessel area

Set liquid hold up volume from residence time

Calculate liquid depth

Set control levels.

Set location of :

Inlet from mist eliminator

Inlet to liquid surface

Disengagement height after demister

g

gl

g Ku

A=Qg/us


Other Sizing Methods

Methods due to Arnold (Surface Production Operations)

These appear different from others as they :

Have built in unit conversions - e.g. Oil and gas units

Allow for gas compressibility

Use a 500m water in oil drop size

Set the liquid level at 50% of vessel diameter



Example: Horizontal 2 phase separator

Gas capacity equation

or

Liquid capacity

There is therefore a trade off between the diameter and length of the separator.

Seam to seam length

m

d

gl

ggeff d

C

P

TZQ420DL

dgl

ggeff CK whereK

P

TZQ42DL

7.0

QtLD lr

eff2

capacity liquid forL3

4=L

capacity gas for12

DLL

effss

effss



Company methods - Best Practice Manuals

These are based on collective experience and should be followed by designers employed by the company, or by contractors working for them. Advantages include

• Application of standards across company and contractors

• Regular updates ensure field experience is built into design rules.

Standards Authorities

American Petroleum Institute Standards

API Spec 12J

NORSOK - Norwegian Oil Industry Association, Federation of Norwegian Engineering Industries

Sizing procedures can be eased through use of spreadsheets


Sizing Methods Summary

1. Souder’s Brown – for maximum gas flow that is possible

• Drop settling velocity – for water-in-oil drop

• Residence time equations – gives the axial velocity of each phase

• Geometry – where hold up volume = length x area

• Residence time in oil phase=residence time in water phase

• Gas density from compressibility factors

• Geometry for filling levels


Sizing Methods - Problems

Sizing methods take no account of

• Drop coalescence

• Drop breakup due to internals

• Hindered settling

• Retention times which vary between lab and full scale

• Actual velocity profile inside separator

• Effect of decreased/increased water cut on dispersion - more water may actually help oil separation

If project allows, have the design verified by independent test


Velocity Profiles

Ideal velocity profile is plug flow, but CFD predictions and now LDA measurements show flow is anything but plug flow in separators without proper internals

Expected flow pattern might be :


Velocity Profiles

Example: “Hansen et al – Gullfaks A Separator” CFD model

Predicts the velocity profile for normal and peak flows through a representation of the separator

CFD model consists of porous plates to simulate packing sections

Note – the separator is 3 phase, but the simulation is only able to work with a single liquid phase.


Velocity Profiles

Example: “Hansen et al – Gullfaks A Separator” CFD model

Predicts the velocity profile for normal and peak flows through a representation of the separator

CFD model consists of porous plates to simulate packing sections

Note – the separator is 3 phase, but the simulation is only able to work with a single liquid phase.


Velocity Profiles

Looking top down

Inlet

Predicted circulation

Are verified in laboratory experiment and suggest residence time will be longer than expected. It also shows flow is NOT plug flow – a deviation from the theory used in finding the size.

Notice relatively fast streamline along base of separator!


Velocity Profiles

Inlet Clear signs of fast streamline along base of separator – resulting in short circuiting –

There will be a stream leaving the separator with LOWER residence time than expected.


Velocity Profiles

Using CFDAlthough CFD has matured, simulating three distinct phases is non-trivial. Examples can be found in literature

Velocity profiles in three phases predicted by CFD

Difficult to predict droplets within each phase but sufficient to give details of flow patterns and influence of internals


Velocity Profiles

Using CFDAlthough CFD has matured, simulating three distinct phases is non-trivial. Examples can be found in literature


Vessel Internals

Inlet Diverter/Momentum Breaker

This makes sure feed is directed towards one end of vessel, maximising distance liquid can use

Basic Dished Plate or Half Pipe


Vessel Internals


Proprietary designs have been developed by several operators and vendors to improve initial separation of oil from gas and to reduce tendency for system to foam.

Natco’s Porta-Test Issues:

Distribution of flow into each cyclone

Velocity to achieve cyclonic flow

Pressure drop

Operating range


Vessel Internals


Proprietary designs have been developed by several operators and vendors to improve initial separation of oil from gas and to reduce tendency for system to foam.

Kvaerner Process Systems


Vessel Internals

High Efficiency designs

To reduce the size of conventional separators, and to combat the tendency to reduce foam, several vendors employ cyclonic inlet devices.

Natco Systems


Vessel Internals

High Efficiency designs

To reduce the size of conventional separators, and to combat the tendency to reduce foam, several vendors employ cyclonic inlet devices.

Natco Systems


Vessel Internals

Vortex Breakers

Rate of liquid withdrawn from separator may lead to formation of a vortex

A simple plate above the outlet is used to prevent the vortex from forming

4D

D/2

D

Vortex Breaker


Vessel Internals

Vortex Breakers

Two general types – plates and gratings -


Vessel Internals

Pipe Diameters

Flanges on the inlet and outlet “nozzles” allow pipe work to be joined to vessel. Diameters of these pipelines and hence nozzles depend on kinetic head/pressure drop limits.

Recommended limits are:


Vessel Internals

Pipe Diameters

Run lengths are also recommended to ensure flow is relatively streamlined before and after the separator.

5xDi

Inlet Nozzle Diameter Di

Gas outlet nozzle Diameter Dg

2xDg

2xDo

Liquid outlet nozzle Diameter Do


Vessel Internals

Mist Eliminators

Small liquid droplets present in the gas stream can be carried along with the gas stream and contaminate the gas processing system. Mechanical devices to capture droplets are used close to gas outlet.

Droplets are removed by impingement on solid surface when liquid collects and eventually drips off from unit.


Vessel Internals

Vane Packs

These change the direction of the gas flow, relying on the momentum of liquid droplets to carry drops towards solid surface. Liquid collects and is drained by special channels, or down inside of vanes.


Vessel Internals

Vane Packs

Some vane packs disrupt

the direction of flow

Operational issues with vane packs include:

• Flooding – too much liquid or where liquid is unable to run free from pack

• Deposition of solids – waxes

• Pressure drop across pack


Vessel Internals

Fibre & Wire Mesh Pads

Similar construction but different pressure drop characteristics

InertialImpaction

DirectImpaction

BrownianDiffusion

Three Mechanisms of Mist Capture


Vessel Internals

General comparison between mist eliminator types

Pressure drop across vane packs will depend on spacing


Vessel Internals

Plates are usually single sheets with perforated holes or squares on triangular or square pitch. Some double sheet systems give better performance.

Square “holes” on triangular pitch

Double plate arrangement, with larger holes either before or after a plate with smaller holes


Vessel Internals

Plates are usually perpendicular to direction of flow, but can be parallel to reduce re-circulation patterns developing


Vessel Internals

Where foam on the liquid surface is a problem, defoaming packs can be used to break foam down

Foam is caused by gas bubbles trying to

break through liquid surface

Packs are similar to vane type mist eliminators, usually submerged 10 to 20 cm below surface


Alternative Separator Layouts









Oil and Gas ProcessingG.White EPS Chemical Engineering


Key Points

A single vessel may not be able to cope with all production conditions

Using novel internals helps to increase capacity• Increased production rates -> lower residence times• Heavier oil fractions -> more difficult separation.• More difficult to access before installation


Floating Production Systems

Floating production systems are typically used for MARGINAL field developments:

Limited recoverable reserves

Deep water

Offloading difficulties

FPSO - Floating Production Storage and Offloading


Motion Effects on Offshore Equipment

Typical topside unit operations

Two phase gas/liquid separators

Three phase gas/oil/water separators

Trayed Distillation Columns - fractionation

Packed Columns – de-oxygenation, acid gas removal

Condensers – tube bundle or tube and fin gas liquefaction

(Re)boilers – Gasification of LNG

Single-phase heat exchangers

Storage tanks

Pumps & Compressors

Flare systems



Typical topside unit operations

Two phase gas/liquid separators

Three phase gas/oil/water separators

Trayed Distillation Columns - fractionation

Packed Columns – de-oxygenation, acid gas removal

Condensers – tube bundle or tube and fin gas liquefaction

(Re)boilers – Gasification of LNG

Single-phase heat exchangers

Storage tanks

Pumps & Compressors

Flare systems



Gas/Liquid or Gas/Liquid/Liquid Separators



Platform motion affects :Separation Equipment Columns


Equipment Affected by Sea Motion

Gravity Separation Systems Spills over weir plate Level control

Columns Distillation - uneven liquid distribution on trays, preferential gas flow on

one side of plate Absorption - preferential liquid flow to one side, reduction in contact

between gas & liquid Uneven distribution of liquid from distributor

Heat Exchangers Liquefaction & re-gassification - where distribution of liquid is affected by

sustained angles of tilt .


Liquid Response to Motion

Two Effects

At non-resonant conditions Spirit level effects - reduce gas area through motion cycle Possible flow over weir plate Problems in level control

Towards resonance Oil/water interface can break-up causing mixing and further dispersions Large oil/water interface amplitude Increase in liquid velocity reducing separation Possible jetting of liquid through internals Possible spillage of water over weir plate


Reducing Motion Effects

Resonant effects depend on natural period hence the fill depth/length ratio. Cutting down the vessel length might help -

Making the vessel shorter Inserting perforated baffles Using structured Packing

Moving vessel to location where amplitude of motion is reduced e.g. center of gravity

Using a vessel with better sea keeping abilities - converted drilling rigs and TLP’s respond to all 6 degrees of freedom. Ship based structures are more susceptible to roll than pitch, although actual motion is more severe.

Using different designs, which respond better to motion.


Common internals with gas/oil separators include Vortex breakers Mist eliminators Defoaming packs Baffle Plates.



Recent innovations have been to use structured packing which promotes coalescence



Packing is similar to corrugated paper but allows flow through the pack while droplets of dispersed phase have a chance to collide and coalesce.


“Performax Packing” Structured Packing


Baffle ReplacementsSome operators have replaced baffled with structured packing


CONOCO’s designs for Hutton


Sand Wash Systems

Certain fields produce solids - sand of small particle size. This can build up along the base of separators and increase erosion damage downstream.

Solids buildup reduces liquid area, increasing bulk velocity. Stagnant areas lead to higher corrosion


Sand Wash Systems

Removing Options

Shut down & manual removal

Automatic removal is via jet wash system:

Series of jets directed to push sand towards central sand trough

Jets angled to prevent excessive erosion of sides

Jet wash system used by Conoco(Courtesy Soc. Pet. Engineers)


Summary

Separation theory Drop settling Retention times Sizing constraints

Types of equipment Horizontal & vertical pressure vessels

Internals Mist pads Baffles, Coalescing packing Vortex breakers

Operational Problems Foams, slugging, level control Velocity profiles

Use on FPSO’s Reducing effects of motion

Documents

Presentation 2009oil and gas