Exp Pr Pr070 en r0_1 Separation

8/9/2019 Exp Pr Pr070 en r0_1 Separation

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PROCESS

SEPARATION

TRAINING MANUALCOURSE EXP-PR-PR070

Revision 0.1


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Exploration & ProductionProcess

Separation

Training course: EXP-PR-PR070-EN

Last revised: 30/04/2007 Page 2 / 150

PROCESS

SEPARATION

CONTENTS

1. OBJECTIVES ..................................................................................................................6 2. THE FUNCTIONS OF SEPARATION..............................................................................7

2.1. INTRODUCTION.......................................................................................................7 2.2. WHY IS THE EFFLUENT PROCESSED? ................................................................8 2.3. DEFINITIONS OF A SEPARATOR .........................................................................11 2.4. THE FINISHED PRODUCT.....................................................................................12

2.4.1. BASIC PRINCIPLES.........................................................................................12 2.4.1.1. Specific gravity ...........................................................................................12 2.4.1.2. Flow point...................................................................................................13 2.4.1.3. Viscosity.....................................................................................................13 2.4.1.4. Definition of the true vapour pressure (TVP) ..............................................14 2.4.1.5. Definition of the REID vapour pressure (RVP) ...........................................14

2.4.2. Characterisation of the product.........................................................................15 2.4.3. Evolution of the effluent ....................................................................................19 2.4.4. Product specifications.......................................................................................21

2.4.4.1. H2S specification .......................................................................................23 2.4.4.2. Water and salt content acceptable for transport.........................................23

2.4.4.3. Water and salt content for “Refining”..........................................................24 2.5. THE IMPORTANCE OF SEPARATION ..................................................................25 2.6. EXAMPLE OF A SEPARATOR...............................................................................26 2.7. EXERCISES............................................................................................................27

3. THE SEPARATION PROCESS .....................................................................................31 3.1. INTRODUCTION.....................................................................................................31 3.2. SECTIONS..............................................................................................................33

3.2.1. The primary separation section.........................................................................33 3.2.2. The secondary separation section ....................................................................34 3.2.3. The coalescence section ..................................................................................34 3.2.4. The collecting section .......................................................................................35

3.3. PROCESSES..........................................................................................................36 3.3.1. Evolution process of hydrocarbons in production .............................................36 3.3.2. Flash process ...................................................................................................38 3.3.3. Differential process...........................................................................................39 3.3.4. Composite process...........................................................................................40 3.3.5. Comparison of flash and differential processes ................................................42

3.4. APPLICATION TO SEPARATION ON FIELDS.......................................................43 3.4.1. Application ........................................................................................................43 3.4.2. Application example..........................................................................................45

3.4.2.1. Data ...........................................................................................................45

3.4.2.2. Optimisation ...............................................................................................46 3.4.2.3. Selection of the number of stages..............................................................49


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3.5. THE INFLUENCE OF PRESSURE AND TEMPERATURE.....................................50 3.5.1. Ashtart case study (Tunisia) .............................................................................50 3.5.2. Breme case study (Gabon)...............................................................................51

3.6. EXERCISES............................................................................................................53 4. THE DIFFERENT SEPARATION PROCESSES ...........................................................56

4.1. HORIZONTAL SEPARATOR..................................................................................56 4.1.1. Two-phase horizontal separator .......................................................................57 4.1.2. Three-phase horizontal separator.....................................................................58 4.1.3. High pressure horizontal separator with liquid retention capacity .....................61

4.2. VERTICAL SEPARATOR........................................................................................63 4.2.1. Two-phase vertical separator............................................................................64 4.2.2. Three-phase separator .....................................................................................66

4.3. SPHERICAL SEPARATOR.....................................................................................67 4.4. GUTTER SEPARATOR FOR ANTI-FOAM TREATMENT ......................................68

4.5. DECANTATION TANKS AND WASH TANKS ........................................................70 4.6. FWKO (Free Water Knock Out)...............................................................................71 4.7. "CENTRIFUGAL" SEPARATOR .............................................................................72

4.7.1. Cyclone-effect separator...................................................................................72 4.7.2. Vortex-effect separators ...................................................................................75

4.8. DROPLET ELIMINATORS ("DEMISTERS") ...........................................................75 4.9. SLUG CATCHERS..................................................................................................76 4.10. OTHER TYPES OF SECONDARY SEPARATION PROCESSES ........................76

4.10.1. Electrostatic dehydrators ................................................................................76 4.11. TREATER HEATERS............................................................................................77 4.12. ADVANTAGES AND DISADVANTAGES OF THE DIFFERENT TYPES..............78

4.12.1. Three-phase separator, FWKO.......................................................................78 4.12.2. Batch processing tanks or cisterns. ................................................................78 4.12.3. Wash-tank or continuous decantation tank.....................................................79 4.12.4. Treater-heater.................................................................................................80 4.12.5. Electrostatic dehydrators ................................................................................80 4.12.6. Summary of advantages and disadvantages..................................................82 4.12.7. EXERCISES...................................................................................................83

5. SEPARATOR REPRESENTATION AND DATA............................................................84 5.1. PROCESS FLOW DIAGRAM (PFD) .......................................................................84 5.2. PLOT PLAN ............................................................................................................87 5.3. PIPING & INSTRUMENTATION DIAGRAM (PID) ..................................................89 5.4. SEPARATOR DATASHEET....................................................................................91

5.4.1. Compressor suction scrubber...........................................................................91 5.4.2. Slug catcher......................................................................................................92

5.5. SEPARATOR SIZING.............................................................................................93 5.5.1. Typical example................................................................................................93 5.5.2. Sizing................................................................................................................96

5.5.2.1. Vertical separators .....................................................................................96 5.5.2.2. Horizontal separators .................................................................................98

5.6. EXERCISES..........................................................................................................100 6. SEPARATORS AND THE PROCESS .........................................................................101

6.1. LOCATION AND CRITICALITY ............................................................................101 6.2. RELATED PROCESSES ......................................................................................103


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6.2.1. Chemicals.......................................................................................................103 6.2.1.1. Flocculants...............................................................................................103 6.2.1.2. Coalescing agents....................................................................................104

6.2.1.3. Wetting agents .........................................................................................104 6.2.1.4. Use of chemicals......................................................................................104

6.3. EXERCISES..........................................................................................................106 7. AUXILIARIES...............................................................................................................107

7.1. LEVEL CONTROL DEVICES................................................................................107 7.2. PRESSURE CONTROL DEVICES .......................................................................108 7.3. TEMPERATURE CONTROL DEVICES................................................................110 7.4. VALVES ................................................................................................................110 7.5. FLOWMETERS.....................................................................................................111 7.6. EXERCICES .........................................................................................................112

8. OPERATING PARAMETERS......................................................................................113

8.1. NORMAL OPERATION.........................................................................................113 8.1.1. Separation parameters ...................................................................................113 8.1.2. Controls to be carried out ...............................................................................114 8.1.3. Positioning of the valves in normal operation: ................................................114

8.1.3.1. Safety valves............................................................................................114 8.1.3.2. Regulating valves.....................................................................................115

8.2. SAFE OPERATION...............................................................................................116 8.2.1. Alarms and safety...........................................................................................116 8.2.2. Valves in Emergency Shut Down position (ESD-1) ........................................118

8.2.2.1. Safety valves............................................................................................118 8.2.2.2. Regulating valves.....................................................................................118

8.3. MAX / MIN CAPACITIES.......................................................................................119 8.4. EXERCISES..........................................................................................................120

9. SEPARATION OPERATION........................................................................................121 9.1. COMMISSIONING AND SHUTTING DOWN A SEPARATOR..............................121

9.1.1. Commissioning a separator ............................................................................121 9.1.2. Shutting down a separator..............................................................................122

9.2. PROVISION ..........................................................................................................122 9.3. 1

ST LEVEL MAINTENANCE..................................................................................123

9.4. EXERCISES..........................................................................................................124 10. TROUBLESHOOTING...............................................................................................125

10.1. EMULSIONS.......................................................................................................125 10.1.1. What is an emulsion? ...................................................................................125 10.1.2. Sources of emulsions ...................................................................................125 10.1.3. How separation occurs .................................................................................126 10.1.4. Flocculation-coalescence .............................................................................127

10.2. FOAMING ...........................................................................................................128 10.2.1. What is foaming?..........................................................................................128 10.2.2. Anti-foam treatment ......................................................................................130

10.2.2.1. Flow straightening ..................................................................................130 10.2.2.2. Chemical treatment ................................................................................130 10.2.2.3. "DIXON plates".......................................................................................131

10.2.2.4. Hot washing ...........................................................................................131 10.3. EXPERIENCE FEEDBACK.................................................................................132


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10.4. EXERCISES........................................................................................................133 11. GLOSSARY...............................................................................................................134 12. FIGURES...................................................................................................................135

13. TABLES.....................................................................................................................138 14. CORRECTIONS FOR EXERCICES ..........................................................................139


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1. OBJECTIVES


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2. THE FUNCTIONS OF SEPARATION

2.1. INTRODUCTION

Figure 1: Situation of the separation in a processing of oil

Generally, the crude oil which leaves a well is a 3-phase combination comprising:

A gaseous phase

A hydrocarbon liquid phase (thecrude itself)

An aqueous phase (formation water)

This effluent may also convey solid particlesin suspension, such as sands from theformation, corrosive products, paraffin-baseor asphalt-base components that haveprecipitated out.

Figure 2: Example of a separator


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This well crude effluent cannot be commercialised as is. It has to be processed to conformto the commercial specifications required by the customer.

This processing may require the implementation of several processes to obtain a crudeconform to specifications.

The separator is a device used for separation and therefore for dissociating oil, gases andwater contained in the effluent leaving a production well, by acting on their density.

2.2. WHY IS THE EFFLUENT PROCESSED?

Figure 3: General diagram of the processing of well effluents

For safety reasons:

o To monitor H2S: H2S is hazardous to human life

o To stabilise the effluent: limit degassing and reduce the risks of explosion


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For technical reasons:

o Stable products (vapour pressure specification to be observed, therefore

the crude must be stabilised). A product is stable if it does not change withtime. The sooner it is stabilised, the less gas it will release.

o Measurable products (this means that can it be metered, without water,without sediment, without gas, to know exactly the quantities sold)

o Pumpable products (the crude needs to be transported from the terminal tothe tanker, and from the tanker to the refinery)

o Non-scaling products (this means that they do not cover the barrels, pipes,or tanks with a mineral layer (paraffins), for example, sulphate, carbonate

deposits etc…)

For commercial reasons:

o Anhydrous products (customers do no want to transport water)

o Non corrosive products (protection of the tanker, refineries and customers:salts-H2S)

To guarantee:

o Safe transport (so as to limit the risk of degassing in the tankers withsubsequent risks of explosion)

o A regular supply of produced hydrocarbons (by, for example, correctprocessing of foaming and emulsions in order to prevent having to stop theprocessing chain.)

To discharge components without commercial value into the immediateenvironment, without polluting:

Example: production waters have no value, they can therefore be discharged (orre-injected if there are no legal restrictions), provided they are processed topreserve the environment.

Stabilisation eliminates part of the gas but also part of the H2S. However, sometimes thisis not enough. Gas sweetening (acid removal) must also be planned. This treatmentprocess will be covered in another course.

As indicated above, stabilising a crude produced from a reservoir consists in meetingcertain specifications, particularly RVP (Reid Vapour Pressure) and an H2S specification ifthe crude contains a significant quantity of it.


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The RVP (Reid Vapour Pressure) is linked to the concentration of gas dissolved in thecrude. The higher the dissolved gas concentration, the higher the RVP. To meet an RVPspecification, it is necessary to implement a process that will, at the least cost, release the

dissolved gas in the crude leaving the well.

The simplest means of stabilising a crude is to subject it to a certain number of separationsat decreasing pressures (multi-stage separation) and to separate the gas obtained at eachone of the separation stages. This process can only be applied for natural flowingreservoirs whose wellhead pressure is higher than the atmospheric pressure. However,these well activation methods, whether pumping or gas lift, help increase the wellheadpressure and use this process in this type of well.

Very often, this simple physical separation is not sufficient. Additional processing must betherefore performed, consisting in heating the crude to improve gas removal. Distillation

may be added to the heating (often by H2S stripping) to limit loss of "semi-light" or "semi-heavy" components, such as the C5, and even C6 in the gas phase extracted from thecrude. However, it may also be necessary to cool the crude as it is too hot and losses maytherefore occur.

As for the H2S removal, if required, simple multi-stage separation will not be sufficient inmost cases. "Stripping" (vaporisation, usually with water vapour, of the oil fractions toreduce the content of excessively volatile compounds) of the crude may be installed inaddition to separation.

This course deals with the separation process. This process is one of the most important

and, often, the most used in a plant.

In the following chapters, we will study separation, which is one of the most important, andoften the most used process in the facilities.

Figure 4: Separation principle


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2.3. DEFINITIONS OF A SEPARATOR

Separators are installed at the head of the processing chain, in which they are theessential elements. They receive, directly from the inlet manifold, the production broughtfrom the collecting pipes.

A separator is a capacity under pressure incorporated into a circuit, in which it slows theflow velocity of the effluent.

A separator is a cylinder positioned either vertically or horizontally.

There are also spherical separators, but they are not used so commonly. Branchconnections with valves and measuring devices are used to control the operation.

According to the specific use, separators can be classified into:

Flash separators used for condensate gas processing

Gas/oil separators

Free water separators

Test separators

Scrubbers (e.g. a flare drum) and filters

The different types will be described in a chapter below.


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2.4. THE FINISHED PRODUCT

This is a combination of hydrocarbons and not hydrocarbons from a reservoir. The effluentis characterised by its composition and its physicochemical characteristics. Thesecharacteristics will change over time and vary widely with the crude.

The effluent of a production well is a combination which is usually in a two-phase form:

A liquid phase including heavy hydrocarbons, stable in the processing conditions,light vaporisable hydrocarbons and formation water.

A gaseous phase formed by gas and light hydrocarbon vapours.

2.4.1. BASIC PRINCIPLES

2.4.1.1. Specific gravity

Oil

't at water of volumecertainaof massVacuum

t t a product of volumecertainaof massVacuum gravity pecificS =

Thus for product exports:

t = 15 °Ct’ = 4 °C

specific gravity is noted d 154 .

The specific gravity of water in a vacuum at 4°C = 999.972 kg/m³.

Gas

ir aof ensity D

Gas theof ensity D gravity pecificS =

in the same conditions


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Dry air

Molecular mass : 28.966 g/mol,

density : 1.2929 g/l,

molecular volume : 22.40 l/mol (0°C-1 bar).

2.4.1.2. Flow point

The crude is slowly cooled without agitation. The liquid will finally gain in mass and will notflow when the specimen is held horizontally. This is the congealing point (sometimes

called the setting point).

If the product is heated after extended cooling, the temperature at which the productbecomes fluid is called the flow point. This flow point is higher than the congealing point bya few degrees.

In practice, the setting point is measured and the following formula applied:

Pflow = Pcongealing + 3°C

2.4.1.3. Viscosity

Viscosity is a physical value measuring the internal resistance of a fluid to flow. Thisresistance is due to friction between molecules coming into contact. Dynamic (orabsolute) viscosity mu is often expressed in poise or centipoises (cPo). However, thelegal dynamic viscosity unit is Pa.s. A practical sub-multiple of the above unit is the mPa.s, which is equivalent to 1 cPo.

Kinematic viscosity is the ratio between dynamic viscosity and density at the sametemperature.

This was formerly expressed in stokes or centistokes (C.G.S. unit system). According tothe International System (S.I.), the kinematic viscosity unit is m2.s-1 and its practical sub-multiple is expressed as mm

2.s

-1.

ρ =v

µ = cpo = g/cm.s

ρ = kgg/m³ or g/dm³ or g/L.v = csto


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Kinematic viscosity is measured by measuring the time it takes, t, for a product to flowbetween two marker lines on a graduated capillary tube. Very often, calibrated empirical

viscometers are simply used (flow time of a standard quantity of product via a calibratedorifice).

NB:

The Germans use the ENGLER viscometer, the English use REDWOOD devices, whichare based on the same principle.

Viscosity is stated in ENGLER degrees or REDWOOD seconds.

The current trend is to state kinematic viscosity in centistokes.

Viscosity is a significant criterion in assessing the pumpability of products and the flowtype in piping.

2.4.1.4. Definition of the true vapour pressure (TVP)

The vapour pressure of a crude or "True Vapour Pressure" (TVP) under storage conditions(atmospheric pressure and ambient temperature) is difficult to measure rapidly: it requireslaboratory equipment. However, it characterises the stable quality of the crude andtherefore its gas-release potential.

Too high a vapour pressure of the crude will cause, therefore, some risks for storage andtransport.

2.4.1.5. Definition of the REID vapour pressure (RVP)

An easily measurable value has been used instead of TPV, so long as there is access to

samples of the crude, which is always possible on the production site and even on an oilcarrier or at the refinery. This value is the REID vapour pressure (RVP).

The RVP of a crude oil is always measured at 100°F (37.8°C)

The RVP measuring instrument (Figure 8) includes 2 chambers: one (1/3 of the totalvolume of both chambers) receiving the crude collected at sampling tap where the deviceis connected, and the other (2/3 of the total volume of both chambers) filled with air.

Once the collecting operation has been done, the tap is opened and the 2 chamberscommunicate with each other. The assembly is then vigorously shaken and put at a

temperature of 100°F.


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The pressure indicated on the manometer connected to the device is then read. Thepressure shown is the RVP.

The RVP is an effective pressure and isnormally expressed in PSI ("pounds persquare inch") which is the Anglo-Americanmeasuring unit for pressure.

The RVP specification of a crude oildepends on the climatic conditions on theproduction site (for crude storage) and onthe route taken by the oil carrier (in case ofcarriage by sea) to the consumer market.

Usually, the RVP is between 7 and 10 psi.A.

Figure 5: RVP measuring instrument

2.4.2. Characterisation of the product

The product is characterised by:

Its composition in terms of Cn H2n+2 hydrocarbons and non-hydrocarboncompounds such as:

H2S

N2 E.g. in molar %

H2

CO2

SaltIn oil, in water

Water

Sediments-noted sediments)ater w(oil Volume

sediments)(water Volumewatercut or BSW

++

+=)(


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The following characteristics:

density,

flow point,

viscosity,

tendency to emulsify with water.

Example: Characteristics of the ROSPO MARE effluent

Composition (%):

N2 1.927

CO2 0.428

H2S presence

RHS presence

C1 1.583

C2 0.774

C3 1.037

IC4 0.726

NC4 2.641

IC5 2.288

NC5 3.839

C6 10.021

C7+ 74.736

molar mass 544

specific mass 1 006 kg/m3

GOR = 3 Sm³/m³ at 30 °C and 1 bar abs,


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presence of H2S and mercaptans (approx. 500 ppm of H2S-80 ppm RSH dosed with thegas separator),

stock tank oil specific mass (15 °C) = 987 kg/m³,

reservoir effluent bubble point pressure = 11.8 bars (abs) at 70 °C,

viscosity of the anhydrous (dry) oil:

30°C 9 500 cst

55°C 980 cst

70°C 290 cst

Newtonian behaviour except for high water content.

Other characteristics of stock tank oil:

flow point : +3°C

total sulphur content in % weight : 6-6.5

paraffin content in % weight : 1.1

melting point for paraffin °C : 38.5

asphaltene content in % weight : 15

Conradson carbonate content in % weight : 20.5

ash content in % weight : 0.09

metal content in ppm

o Nickel : 56o Vanadium : 135

Formation water

specific mass : 1 027 km/m3 at 15 °C

salt content (equivalent NaCL) : 42 g/l

pH : 7.2


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Na+ content : 13.4 g/l

Ca++ content : 2.5 g/l

Ka+ content : 0.4 g/l

Mg++

content : 0.36 g/l

C- content : 25.1 g/l

SO4-- content : 1.2 g/l

CO3H- content : 0.4 g/l

H2S

H2S gas content higher than that indicated above has been measured on the RSMA atvarious stages:

Atmospheric pressure:

flash gas at 22 °C 6 600 ppm

flare circuit at 80 °C 60 000 ppm

stocker at 50 °C 5 000 ppm


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2.4.3. Evolution of the effluent

The presence of water in the reservoir explains the presence of varying amounts of waterin the effluent.

In general, water content increases over time. The following charts show this evolution.

Appropriate processing for this effluent may change over time.

Figure 6: Evolution of an oil field over time


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Year

Liquid

production106m³/year

BSW

%

Water


Oil

production106m³/year GOR

Gas


1 1.5 0 1.5 53 79.5

2 2.5 0 2.5 53 132.5

3 2.5 0 2.5 53 132.5

4 2.5 0 2.5 56 140.0

5 2.5 2 0.05 2.45 68 166.6

6 2.25 3 0.07 2.18 81 176.6

7 1.75 5 0.09 1.66 120 199.2

8 1.75 7 0.12 1.63 150 244.5

9 1.25 10 0.12 1.13 175 197.7

10 1.25 15 0.19 1.06 190 201.4

11 0.75 22 0.16 0.59 200 118.0

12 0.75 30 0.22 0.53 205 108.6

TOTAL 21.25 1.02 20.23 1897.1

Table 1: Evolution of an oil field over time


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2.4.4. Product specifications

As is indicated above, the problem consists in separating a complex effluent into agaseous phase and one or several liquid phases.

The role of a separation unit, and therefore a separator is to eliminate the formation water,to process the oil so that there is almost no release of gas at atmospheric pressure, and toensure that the gas released is as dry as possible.

The figure below illustrates the path and changes undergone by the effluent between thereservoir and the processing centre:

Figure 7: Path of the effluent between the reservoir and the processing centre


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These same changes can be followed on a P-T diagram representative of the reservoirfluid-(Figure 8).

Figure 8: P-T diagram representative of the changes of the fluid during its transit

The fluid in place in a reservoir is a mixture of liquid and/or gaseous hydrocarbons and

water. This mixture is originally in a state of equilibrium that depends on its compositionand on the pressure and temperature conditions in the formation.

Whatever the type of crude oil to be processed, the specifications of the product remainapproximately the same, i.e.:

R.V.P. 7-10 PSI

H2SMediterranean 30-40 ppm massMiddle East 70-80 ppm mass

Water contentDeparture 0.1% vol. Arrival 0.2% vol.

Salt contentDeparture 40-60 mg/l.NaCl Arrival


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2.4.4.1. H2S specification

The well effluent very often contains, in more or less large quantities, a toxic contaminant:

H2S. This component preferentially migrates to the gaseous phase, but a non negligiblequantity remains in the released crude.

An H2S-concentration of 100 ppm in the ambient air (following degassing in the storage,related to a temperature rise, for example) may lead to very serious consequences on thepersonnel brought in to work around the location of the crude.

Let us remember that in the presence of water, H2S results in corrosion problems (H2S +liquid water = sulphuric acid).

H2S extraction from the crude oil may require the implementation of a so-called "stripping"

process.

Generally, the H2S-concentration in stored crude should not exceed a weight of 100 ppm.

2.4.4.2. Water and salt content acceptable for transport

The field-processed crude is generally sent to refineries.

The usual transport means are:

Pipeline

Rail

Carriage by river

Carriage by sea (by Tanker)

Pipeline

For pipeline transport, the water content is much more important for the carrier than thesalt content. In this case, the water is paid at the crude price and unnecessarily overloadsthe pipeline. It may also result in corrosion problems increased by the presence of salt.

Consequently, the water content of a crude transported by pipeline should normally notexceed 0.1% (vol.).The salt content (chlorine expressed as NaCl ) should not exceed 60 mg/l.


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Other transport means

Where transport is other than by pipeline, there really are no constraints set by the carrier.

For all other means, carriage by sea causes the most contamination due to use ofseawater as ballast.

Statistics show that the additional salinity owing to carriage by sea varies between 8 and37 mg/l and may even reach 50 mg/l.

2.4.4.3. Water and salt content for “Refining”

The salt content of the crude at the refinery, before entering the preheating string towardsthe distillation column ("topping"), must decrease to 5 to 10 mg/l of salt, so as to avoidproblems such as:

Fouled heat exchangers

Corroded equipment

Degraded quality of the refined products

With a desalting stage as found in European refineries, the crude salinity value of 5 mg/ldownstream of desalting corresponds to a maximum salinity of 100 mg/l in the crude at therefinery inlet.

Thus, the maximum salinity of a crude delivered to a refinery should not exceed 100 to 110mg/l and 0.2% of water.

Consequently , in view of the pollution brought by carriage by sea (when carried bytanker), the salinity of the crude leaving the site should not exceed 60 mg/l and have awater content less then 0.1%.

Better control of loading procedures, the widespread use of washing of the tanker vesselswith crude for example, should help decrease the pollution due to carriage by sea andtherefore slightly extend the salt specification of the crude leaving the production site (upto 80 mg/l).


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2.5. THE IMPORTANCE OF SEPARATION

After this digression into explaining specifications required for the finished product, let usreturn to the device that we were describing and mainly to the importance it plays in theprocess part.

In Table 1, the importance of the separator (whether there are two, one or none at all) canclearly be seen, in the final product quality. (In particular on the gas/oil ratio).

However, do not assume that the more separators there are, the greater the amount ofgas recovered.

Reservoir Separator1

Separator2

Stocktank

TotalGOR

Sm3/Sm

3

Pressure b.eff 245 - - 0 -

Temperature °C 127 - - 15 -

GOR Sm3/Sm3 - - - 234.1 234.1

Pressure b.eff 245 22 - 0 -

Temperature °C 127 22 - 15 -

GOR Sm3/Sm3 - 159.8 - 34.9 194.7

Pressure b.eff 245 69 14 0 -

Temperature °C 127 54 40 15 -

GOR Sm3/Sm3 - 115.5 52.5 24.3 192.3

Table 2: Reservoir fluid separation tests


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2.6. EXAMPLE OF A SEPARATOR

When speaking about a separator, one usually thinks about production separator(s)located upstream of the processing chain.

However, there are different types of separators depending on the fluids which arecirculating in these drums. These will be detailed in the following chapter.

Figure 9: View of a three-phase separator (Girassol test separator)

The production separators are designed to receive a continuous flow from the wells.

This type of capacity separates the gases from the liquids. As this separator is a three-phase device, it will also separate the water from the oil.


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2.7. EXERCISES

1. What are the three elements of the effluent that a three-phase separator dissociates?

2. The separator acts on the density of the effluent components in order to separate them.

True

False

3. Crude oil does not need to be processed in order to be commercialised.

True

False

4. Give two technical reasons why the effluent must be processed.

5. Give one commercial reason why the effluent must be processed.

6. Give one environmental reason why the effluent must be processed.

7. What do the initials R.V.P. mean?


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8. The RVP (Reid Vapour Pressure) specification is linked to the gas content dissolved inthe crude.

True

False

9. The more the dissolved gas content decreases, the more the RVP of the crude willincrease.

True

False

10. On natural flowing reservoirs with a wellhead pressure higher than the atmosphericpressure, what is the simplest method used for stabilising a crude?

11. Complete the diagram of the separation principle

12. Where are the separators located on the oil processing chain?

At the beginning

At the end


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13. Using the definitions given in the diagram below, indicate the correct location of therelevant pressures.

14. In the P-T diagram below showing the changes in the fluid during its transit path (redline), indicate the correct location of the relevant pressures.


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15. Usually, the RVP specifications of the finished product are between:

_____________ and ____________ psi.

16. Usually, the water content from the installation is:

_____________ % vol.

17. Usually, the H2S content from the installation is between:

Mediterranean: _____________ and ____________ ppm mass

Middle East: _____________ and ____________ ppm mass

18. Usually, the salt content from the installation is:

_____________ mg/l NaCl

19. What are the two main types of separators?


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3. THE SEPARATION PROCESS

3.1. INTRODUCTION

Processing involves the separation of the main components of the crude effluent to allowfor the delivery of products complying with defined standards to the customer.

The fluid existing in a reservoir is a mixture of liquid and/or gaseous hydrocarbons andwater . This mixture is originally in a state of equilibrium that depends on its compositionand on the pressure and temperature conditions in the formation.

The production process destroys this equilibrium. Subjected to head losses in the reservoirrock, in the borehole and in the collecting pipes, the effluent undergoes successivedecompressions until it enters the processing centre. These decompressions are alsoaccompanied by drops in temperature.

Consequently, gases are released from the oil. Hydrocarbons and water condense fromthe gas.

The Processing Centre therefore receives alternating slugs of hydrated gas, free waterand oil still charged with dissolved gas.

The densities of crude oils range from 0.780 to 1.04 (50 ° at 6 ° API) and the viscositiesfrom 5 to 75 000 cPo.

The processes involved in extracting the crude oil and conveying it to the surfacesometimes cause emulsions and foaming to form. These particular phenomena requirethe installation of specific additional equipment in the processing centre.

When a reservoir of liquid or gaseous hydrocarbons enters in production, several productsof varying separation properties are collected, and not just one homogenous product.

With gas reservoirs, the reservoir usually contains one homogenous fluid. When

reaching the surface, this fluid is expanded and cooled. These pressure and temperaturevariations reveal varying components:

water vapour contained in the gas will partially condense: this will introduce awater-liquid phase;

the heaviest hydrocarbons also condense: this will introduce a second liquidphase, gasoline.

The gaseous phase therefore involves three separate components. These products havedifferent uses, and a significant problem in production is separating these components asfully as possible to rout them to their respective destinations.


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With oil wells, the fluid produced may also be homogenous in bottomhole conditions, butthe expansion at the surface releases a variable quantity of gas from the oil.

Depending on the quantity of gas produced, it may be used or burnt at flares. The oil mustbe separated from the gas under all circumstances.

In all cases, the problem consists in separating a complex effluent into a gaseous phaseand one or several liquid phases.

The role of a separation unit is to eliminate the formation water, to process the oil so thatthere is almost no release of gas at atmospheric pressure, and to ensure that the gasreleased is as dry as possible.

Why is separation necessary? For several reasons:

Technical reasons

It is important to have oil or gaseous fluid which retains single-phase properties, inthe temperature and pressure conditions found in storage and transportinstallations. Indeed, if the oil vapour pressure remains too high after processing,gas slugs will rapidly appear.

These gas slugs will disturb the equilibrium of storage tanks, upset measurements,reduce pump efficiency and create significant and unforeseeable secondary headlosses in pipeline networks.

Similar disadvantages will arise in gas transport lines.

The appearance of condensates due to drops in pressure or temperature willmodify metering, increase head losses, and may, in certain critical conditions, plugconducts via the formation of hydrates.

Economic reasons

Successful separation can increase the volume of liquid recovered by trappinglight components in a non-negligible manner.

It will also increase the trading value of the crude, as the value of crude usuallyincreases with API density, i.e. inversely to its specific weight. In addition, theimmediate elimination of water saves unnecessary transport and maintenancecosts.

Verification reasons

The availability of separated products greatly simplifies the checking of productionat field level. Daily checks are possible on site: checks on the GOR, productivityindex, oil density, salinity, etc...


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3.2. SECTIONS

Figure 10: The different sections in a separator

Apart from the shape, separators usually consist of four main sections in addition to thecommands and controls required.

Primary separation section

Secondary separation section

Coalescence section

Collection section

The locations of these sections, whatever the type of separator, are shown in the figure

above.

3.2.1. The primary separation section

Section A is the primary separation

It is used for separating the main part of free liquid from the inlet fluid. It contains the inletnozzle (also called the intake or feed nozzle) which is generally tangential, or a deflector(also called a diverter plate) to take advantage of the inertia effects of the centrifugal forceor a sudden directional change in order to separate most of the liquid or gas.


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3.2.2. The secondary separation section

The secondary separator or gravity section, B, is designed for using the gravitational

force so as to increase separation of the entrained (carried over by the liquid) droplets.

In this separator section, the gas moves at a relatively low velocity and with littleturbulence.

Figure 11: The differentsections in a spherical

separator

In some cases,straightening vanes areused to reduce theturbulence. These vanesalso act as dropletcollectors and thusfacilitate the separation ofthe droplets and the gas.

3.2.3. The coalescence section

The coalescence section, C, uses acoalescer or a demister which mayconsist of a series of vanes(labyrinth), a braided wire mesh mator even a series of cyclones.

Figure 12: The different sections in avertical separator

This section extracts the very smallliquid droplets from the gas bycollision on a surface where theycoalesce.

Typical liquid entrainment (or carry-over) in a demister is less than 0.013

ml per m3.


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3.2.4. The collecting section

The manifold or liquid collecting section, D, acts as the receiver for all the liquids

extracted from the gas in the primary, secondary and coalescence sections.

Depending on the requirements (conditions), the liquid section should have a certainvolume for gas releasing or appearance of liquid slugs.

In addition, a minimum liquid level is required for a correct operation.

Gas removal may require a horizontal separator with a shallow liquid level whilst theseparation of emulsion may call for a higher liquid level, higher temperatures, and/or theaddition of a surfactant.


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3.3. PROCESSES

3.3.1. Evolution process of hydrocarbons in production

The figure below illustrates the path and changes undergone by the effluent between thereservoir and the processing centre:

Figure 13: Path of the effluent between the reservoir and the processing centre

These same changes can be followed on a P-T diagram representative of the reservoirfluid (Figure 14).

Figure 14: P-T diagram representative of the changes in the fluid during its transit


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In the reservoir conditions, the fluid is a single-phase liquid or in equilibrium at the bubblepressure, PB. When flowing, the fluid enters the two-phase domain and gas content

increases with a decrease in pressure.

The transition shown in the figure may be described using three processes:

flash process,

differential process,

composite process.

These processes systematically lead from one state (P1, V1, T1) to another (P2, V2, T2)

with conservation or loss of the product mass during release.

The determination of optimal separation pressure in the processing of hydrocarbons on theproduction fields, is an application of thermodynamic phase equilibrium.


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3.3.2. Flash process

A fluid is subject to a flash process when its global composition remains constantbetween the initial state (P1, V1, T1) and the final state (P2, V2, T2) where P1 > P2 andstarting from a single-phase (L) or two-phase (L+V) state or complex.

In this process, the results are independent of the path taken between P1 and P2. If thefluid evolves within its two-phase domain with a constant composition and T accordingto a single variable P, this is called a flash liberation.

Figure 15: Evolution of the fluid within a flash separation

The figure shows a P-T diagram of the phase transitions of a real fluid undergoing flashliberation in a drum, followed by flash separation.

When a complex passes from conditions P1 and T1 (P1 = saturation pressure at T1) toconditions P2 and T2 (P2 < P1 and T2 < T1), with its total composition remaining constant,this is called a flash separation.

This liberation occurs in the tubing when the reservoir fluid is rising (wellhead compositionidentical to bottomhole composition).


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This applies at each stage of separation where the effluent is successively subjected to aflash separation at separation conditions.

G1

L1

G2

L2

P1

T1

P2

T2

G1

L1

G2

L2

P1

T1

P2

T2

(Separator inlet) (Separator)

That of oil or gas phases recovered in the next separator will also be subjected to a flashseparation.

3.3.3. Differential process

If we consider a two-phase complex with a given total composition, it is said to evolveaccording to a differential process if the total composition varies by draw-off of all orpart of one of the phases.

A differential process may occur at constant P and T.

If this evolution is executed at constant temperature, this process is known asdifferential liberation.

Such a process will occur in the reservoir when the field is depleting.

G1

L1

G2

L2

P1

T1

P2

T2

Gi

Li

Pi

T1

Gs

G1

L1

G2

L2

P1

T1

P2

T2

Gi

Li

Pi

T1

Gs

The Gs product is drawn off.

The values of Pi affect this phenomenon.

The differential process condition is also created in surface installations, if we consider thetransitions of the effluent in all separators, the stock tank being considered as a(atmospheric) separator.

The following figure shows a P-T diagram of the phase transitions of a real fluidundergoing differential liberation followed by differential separation.


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Figure 16: Transitions in the fluid during differential separation

3.3.4. Composite process

The composite process is, as its name indicates, a combination of flash and differentialseparation.It includes a set of "elementary procedures" executed on the initial complex.

Each procedure is defined as follows:

Through differential liberation (at constant T) the reservoir complex is expandedfrom the initial saturation pressure to pressure P, at the temperature of the

reservoir, TR.

The intermediate complex obtained is assumed to represent the effluentconsidered at the foot of the well when the average pressure for the reservoir is P:

The differential liberation stopped at pressure P is continued via a series of flashseparations representing the evolution of the effluent in surface installations up tostorage.


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The phase diagram showing the various evolutions is given below.

Figure 17: Transitions of the fluid during composite separation

The figure shows a P-T diagram of the phase transitions of a real fluid undergoingcomposite separation

NB: The composite process is not a standard process as it depends on the number ofseparators installed and their operating condition (P, T).


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3.3.5. Comparison of flash and differential processes

Based on a given mass of fluid at saturation pressure (Pb) and at reservoir temperature

(TR) occupying a volume (Vb), first executing a flash process and subsequently adifferential process up to standard conditions (1b-15 °C)

The experiment and laboratory measurements show that the gas quantities released aregreater for flash liberation than for differential liberation for the same final temperature.

T = TR

Pbat oil V gas produced V

RS

=

Figure 18: Comparison of flash anddifferential processes

In a similar manner, the volume of liquidobtained is greater in a differential

process than in a flash process.

The same phenomenon would occur at a different temperature, particularly at ambienttemperature.

The relative difference between the two charts depends on the nature of the oil: low forheavy oils and higher for volatile oils.


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3.4. APPLICATION TO SEPARATION ON FIELDS

3.4.1. Application

In the previous experiment, we assumed that the temperature, T, was that of reservoir TR,but the effect of the process on the gas quantities liberated and oil recovered would beidentical at another T, e.g. ambient T.

1 single separation stage In this case, the fluid is subject to a flash liberation.

G

L

G

L

PiT1

Ps

T1

G

L

G

L

PiT1

Ps

T1

The minimum quantity of oil is obtained and the maximum quantity of gas.

Several separation stages

In each separator, the effluent is subject to a flash liberation, but the series ofseparators represents a differential separation.

In this case, the fluid is subject to differential liberation between P1 and Ps: ateach stage, the gas released is drawn off. The product mass will therefore vary.

Maximum recovery will be obtained for an infinite number of separation stages onthe basis of the saturation pressure.

In practice, the separation pressure for the first stage is imposed by the pressureavailable in the wellhead, the number of stages is a compromise between the costof installations and the expected gains in oil recovery.


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A rule-of-thumb method can be used to show the operating pressures for thevarious intermediate stages.

The pressure ratio between two adjacent stages is:

1

−= n storageP

P separator HP R

with n: number of separation stages (including the stock tank).

Number of stages and separation pressure

Low G.O.R < 20 m3 /m

3

1 Separator 3-7 bar abs2 stages

1 Storage 1 bar abs

50 < average G.O.R < 150 m

3

/m

3

1 HP Separator 10-20 bar abs

3 stages 1 LP Separator 2-6 bar abs

1 Storage 1 bar abs

High G.O.R < 200 m3 /m

3

1 HP Separator 20-40 bar abs

1 AP Separator 5-15 bar abs4 stages

1 LP Separator 2-5 bar abs

1 Storage 1 bar abs


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3.4.2. Application example

Field of PALANCA

Results are expressed in terms of separation yield, i.e. the ratio (in %) between the finalmass of stock tank oil and the mass of hydrocarbons entering the processing centre.

3.4.2.1. Data

Composition of the effluent (molar %)

N2 0.26

CO2 0.85

C1 42.65

C2 10.76

C3 7.68

IC4 1.18

NC4 3.23

IC5 1.22

NC5 1.68

C6 2.90

C7 + 1 5.85

C7 + 2 4.17

C7 + 3 17.51

Fraction characteristics

C7 + 1 molar mass 105

specific mass 758 kg/m³

C7 + 2 molar mass 132

specific mass 782 kg/m³C7 + 3 molar mass 242

specific mass 865 kg/m³


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Reservoir conditions

Depth -2 626 m/rM

Reservoir pressure 295.5 bars

Reservoir temperature 145.8 °C

Wellhead conditions

Maximum pressure 192 bars

Minimum pressure 40 bars

Effluent temperature 120 °C

3.4.2.2. Optimisation

2 theoretical stages

Separator

Pressure : 25, 20, 15, 10 bars

Temperature : 105 °C, 90 °C, 75 °C

Storage : Atmospheric pressure.

Optimal pressure is 19 bars and the temperature must be minimal.

Final yield (recovery) is of 76.1 %.

This therefore corresponds to the ratio between the final mass of stock tank oil and themass of hydrocarbons entering the processing centre.


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Figure 19: PALANCA – Separation yield, stage 2



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Figure 22: PALANCA – Separation yield at 75 °C


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3.4.2.3. Selection of the number of stages

The evolution of the yield is represented according to the number of separation stages fora T° of 75 °C.

A significant increase can be observed between stages 2 and 3, however the increase isnot substantial between 3 and 4, the investment in an additional stage would not beprofitable.


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3.5. THE INFLUENCE OF PRESSURE AND TEMPERATURE

Pressure and temperature also have an effect on Separation yield.

The pressure of the first stage must be optimised to obtain optimum oil recovery on thebasis of the decline data for the field.

A reduction in temperature usually increases recovery (see examples below).

Processing temperature must be:

Low : optimum liquid yield,

Average : optimum water decantation,

High : optimum gas removal and H2S processing.

Leading to a badly sized measurement, or temperatures evolving throughout processing.

3.5.1. Ashtart case study (Tunisia)

Two cases of the oil recovery are studied from the reservoir fluid analysis:

Standard case

Case with wellhead cooling

Figure 23: Standard diagram for Ashtart (Tunisia)


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Figure 24: Diagram with cooling in the Ashtart wellhead (Tunisia)

Conclusions

For the same quantity of reservoir fluid (100 kilomoles/day or Kmol/d), we obtain:

12.306 m3/day oil without cooling.

13.403 m3/day oil with cooling.

i.e. 9 % in additional production.

3.5.2. Breme case study (Gabon)

Recovery of condensates on flare gas

Figure 25: Standard diagram for Breme (Gabon)


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3.6. EXERCISES

20. In the following diagram, indicate, using the letters (A-B-C-D), the main sections of ahorizontal separator.

21. In the following diagram, indicate, using the letters (A-B-C-D), the main sections of avertical separator.


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22. In the following diagram, indicate, using the letters (A-B-C-D), the main sections of aspherical separator.

23. Show the evolution of pressure for the effluent throughout the process on a phase diagram.


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24. List the different separation processes

25. Complete the following phrase:

In each separator, the effluent is subject to a______________ liberation, but the series of

separators represents a _____________separation.

26. Complete the following statements:

Processing temperature must be:

________________________ : optimum liquid yield

________________________ : optimum water decantation

________________________ : optimum gas removal and H2S processing.


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4. THE DIFFERENT SEPARATION PROCESSES

Depending the type of effluent (gaseous or liquid), there are different types of separators.

4.1. HORIZONTAL SEPARATOR

They are often used for wells with high GORs. They have a very high exchange surface.

These separators generally have a smaller diameter than vertical separators for the samequantity of gas and offer a larger gas/liquid interface.

They are also easier to mount on skids.

The following figure shows the typical arrangement of a field separator drum.

Figure 27: Detailed view of a two-phase horizontal separator

These separators are generally mounted on complete skids, including piping, control and

safety equipment.


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4.1.1. Two-phase horizontal separator

A two-phase horizontal separator performs a primary separation close to the separatorinlet. The second separation and the demister are located in the upper part of the capacity.There is a section which collects the liquid in the bottom of the separator.

The effluent coming from the well enters the separator and hits a water breaker walls.

Figure 28: Cutaway view of a two-phase horizontal separator

Most of the liquid is separated. The heaviest liquids fall to the bottom of the separator. Thegas and liquid vapour continue their path across the straightening sections (see figure 23).

These sections cause oil droplets to be formed.

These droplets fall into the liquid collector. The water breaker walls limit the turbulence.

The gas continues its path horizontally across the demisters. Here, almost all theremaining liquid is extracted by this mesh (except certain small droplets). The gas leavesthe separator through the gas outlet at the top of the drum. The collection of liquid islocated in the lower part of the separator. This liquid is separated from the gas by plates(also called trays).

When the liquid reaches the required level, the liquid level controller opens the level valve.The liquid leaves the separator through the liquid outlet.


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4.1.2. Three-phase horizontal separator

The three-phase horizontal separator design is similar to a two-phase horizontal separator.

Figure 29: Cutaway view of a three-phase horizontal separator

The major difference is in the liquid collecting section. In a three-phase separator, theupper part of the liquid collecting section contains the oil whereas the water is found in thelower part.

Each of the liquid sections has itsown controller for their relevant

valve.

Figure 30: Simple diagram of athree-phase separator

When the liquid reaches therequired level, the controllers opentheir respective level valve. Theseparated liquids leave theseparator through the various liquid

outlets.


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Figure 31: Detailed view of a three-phase horizontal separator

Figure 32: Cutaway view of a three-phase horizontal separator


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Figure 33: Exploded view of a three-phase separator (floating separator with flow dividing)


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4.1.3. High pressure horizontal separator with liquid retention capacity

The two tube horizontal separator has an upper tube and a lower tube linked by verticaltubing called "downcomers" i.e. a type of chute.

The upper tube is the separating section of the gas and the lower tube is the collectingsection of the liquids.

The two-tube separator separates better than the single tube separator when there are alot of slugs occurring in the well effluent. Also, the two tube separator has the advantage ofavoiding potential re-entrainment.

The upper tube, which is the gas separator, contains the fluid inlet, the inlet diffuser, thetransition section and the demister. This section also has a safety valve or a burst disk.

Figure 34: Cutaway view of a two-tube three-phase horizontal separator


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The fluid from the well enters the upper tube through the inlet nozzle. The flow is divertedto change its direction and velocity. The liquid falls to the bottom of the upper tube. Thegas and liquid vapour continue their path across the straightening sections. These sections

cause the formation of oil droplets, which fall to the bottom of the upper drum.

The gas passes over a vertical plate and then across the demister. Here most of the liquiddroplets are removed from the gas. The gas leaves the upper tube through the outletnozzle.

The lower tube has a liquid level controller, a liquid outlet nozzle and a drain. The verticaltubes let the liquids flow in from the upper drum to the lower drum. The liquids spread outover the liquid surface in the lower separator. Controlled by the liquid level controller, theliquids leave the lower tube through the liquid outlet nozzle.

The two-tube separator can also be a three-phase separator. The gas still comes out theupper tube and the oil leaves at the top of the lower tube, with the water at the bottom ofthe lower tube.

Figure 35: High pressure two-phase horizontal separator with liquid retention capacity


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4.2. VERTICAL SEPARATOR

The main advantage of this separator is that it can accept larger liquid slugs withoutcausing excessive entrainment in the gas. Considering the great distance there usually isbetween the liquid level and the gas outlet, this reduces the entrainment of liquid droplets.

However, it has a larger diameter for any given gas capacity.

Vertical separators are therefore well suited to large quantities of liquid (low GORs) or, onthe other hand when there is only gas (the minimum liquid space in a horizontal drum istoo great).

Typical applicationsare scrubbers,compressor suction,heating gas drumsand certain oilseparators containingsediments.

They are also usedfor wells with soliddeposits (easy toclean).

Figure 36:External view of

a verticalseparator


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4.2.1. Two-phase vertical separator

Figure 37: Detailed view of a 2 phase vertical oil/gas separator


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Another type of vertical separator isthe gas scrubber. Generally, it isinstalled at the compressor suction.

The name "scrubber" comes from theoil fields.

It simply means that the gaseoushydrocarbons which enter the drumare "scrubbed" (cleaned) of liquids(generally called condensates) whichthe gas has entrained.

The gases arriving in this type ofseparator are "wet gases".

Figure 38: Typical example of ascrubber

They still contain liquids. If these liquids are not separated and enter the gas compressor,they then will cause major damage to the compressor.

A scrubber uses gravity to separate the liquids from the gas. The gas entering theseparator is diverted to the bottom by a deflector installed on the drum inlet line. Thisdirectional change reduces the velocity of the gas and thus causes the liquid droplets tofall to the bottom of the separator.

In the scrubber, the liquid outlet is equipped with an"anti-vortex". This is installed so that the gas cannotleave the separator with the liquids.

Any liquid entrained towards the top of the separator isseparated by a demister placed close to the top of thedrum.

Figure 39: Detailed view of a scrubber


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4.2.2. Three-phase separator

As for the three-phase vertical separator, the internal elements are nearly the same.

Just a water outlet and a regulator are added.

Figure 40: Detailed view of a three-phase separator


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4.3. SPHERICAL SEPARATOR

These type of separators are not very common and are reserved for wells with very highGORs (gas + condensate wells).

They are relatively low-cost and compact, but with a limited liquid retention time anddecantation section. Use in three-phase separation is, therefore, very difficult if notimpossible.

Their advantage is their compact size but they offer small capacities. They are very easyto handle. Another interesting point of importance is that owing to their spherical shape,they can support all pressure ranges.

Figure 41: Two-phase spherical separator


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4.4. GUTTER SEPARATOR FOR ANTI-FOAM TREATMENT

These gutter separators are used for anti-foam treatment. They can be vertical orhorizontal as shown below.

They use Dixon plates which are inclined at 45° with a large contact surface.

Dixon plates require anti-foaming products to operate efficiently.

Figure 42: Detailed view of a vertical gutter separator


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Figure 43: Detailed view of a horizontal gutter separator


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4.5. DECANTATION TANKS AND WASH TANKS

Simple decantation (also termed settling) in tanks has been a very popular process, inparticular in America. Although not acceptable by engineering & design offices, it is,nevertheless, an interesting solution when a sufficiently fast additive cannot be selected. Actually, the main difference with the other separators is that the retention (or residence)time, and therefore the decantation, is very high (several hours).

Despite all the advantages of simplicity, the interest in tank decantation has waned due tosafety and environmental regulatory constraints.

The wash tank concept is linked to the principle of bubbling the production through thewater kept at the bottom of the tank. When the emulsion is not very solid, the bubbling can

break it due to the fatigue of the emulsifying film.

Wash tanks can also be used for solving the problem of potentially crystallised salt insuspension in the oil.

Figure 44: Detailed view of a traditional Wash Tank


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4.6. FWKO (Free Water Knock Out)

Equipment called under the name, boilerseparators, in this document, is used forextracting free water. Let us rememberthat, arbitrarily, water which separates in5 minutes qualifies as free water. Thethermodynamic definition of free water isas follows: free water is that which formsa liquid phase (including the droplets) butdoes not take into account humidity. Theretention time sometimes exceeds thisbut rarely 20 minutes.

They, therefore, they are not reallydehydration devices but are auxiliaries forpreliminary separation. They areparticularly useful when the percentage ofassociated water is high as they allow thesize of downstream installations to besmaller. Furthermore, if heating isrequired during the process, they provideways of saving energy.

Figure 45: Deflector

Figure 46: FWKO-Free Water Knock Out


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4.7. "CENTRIFUGAL" SEPARATOR

This term will be used to designate separators that use centrifugal force as the mainseparating force. They are now available from several manufacturers.

For the purpose of this presentation, the effects of centrifugal force can be classified intotwo main types:

Cyclone effect

Vortex effect

4.7.1. Cyclone-effect separator

The vertical cyclone effect separator is used mainly in gas processing systems. It canremove solid particles and liquids which might have been entrained with the gas.

This type of separator removessolid particles and liquids using

centrifugal force.

The gas enters at the top of theseparator and is forced into awhirlpool movement. Both thesolid particles and the liquid areprojected onto the walls of theseparator.

The solid particles and the

liquid fall to the bottom of theseparator. They leave theseparator through a levelcontrol.

The whirlpool creates a vortexinside the separator. The gas isdisplaced from this vortex (orcyclone) to the top of theseparator.

Figure 47: Vertical cyclone separator


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Some liquids are entrained with the gas in the flow at the top of the separator. There is adead space at the outlet which collects the entrained liquids. These are then recycled inthe separator.

The fluid enters the drum tangentially, along anaxis perpendicular to that at which it leaves thedevice.

The simplest example is that of a tangential inlettube which is horizontal in a vertical drum. Thedroplets projected onto the walls of the separatorflow by gravity. Manufacturers often use, in thistype of equipment, cylinders with pierced conesand orifices oriented so as to give a cyclone

movement to the fluid.

Figure 48: Operating principle of a cyclone effectseparator

Other manufacturers use a series ofsmall cyclones such as those usedfor dust removal.

Figure 49: Cross section view of acyclone

Figure 50: View of an internalmulticyclone


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Figure 51: Example of a Multicyclone separator


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4.7.2. Vortex-effect separators

The fluid enters the separator axis, starts to rotate (vortex) due to small blades located

in the inlet. The liquid is then projected on the walls and is evacuated by meticulouslycalibrated orifices. These tubes can be used alone or in parallel.

The first advantage of this type of separator is its efficiency: 99.9 to 99.9% of all dropletsare greater than 5 to 10 micrometres.

However, usually the quantity of liquid

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Exp Pr Pr070 en r0_1 Separation