Separation of Oil, Gas

SEPARATION OF

OIL, GAS & WATER

1

GAS SOLUBILITY (r)

Defined as the no of cubic Feet of gasmeasured at standard conditions whichare in solutions in one barrel of STO atreservoir pr. & temp.

Typical ‘gas solubility curve’ as a function ofpressure is shown for a “Saturated CrudeOil” at reservoir temperature.

A typical gas solubility curve for an‘undersaturated crude’ is shown.

P & P represent original reservoir pr. &saturation pr. & reservoir pr. respectively.Between P & P gas solubility remainsconstant at ‘r’ but at pressures below P gasis evolved and ‘r’ decreases.

2

OIL & GAS SEPARATOR (TERMENOLOGY)

Flash & Differential liberation of gas:

The solubility of natural gas in oil is a function of pressure& temperature at reservoir conditions. The gassolubility is defined as the number of cubic feet of gasmeasured at std. conditions which are in solutions inone barrel of S.T.O. at reservoir temp. & pressure.

If the pressure is released from a sample of reservoircrude oil the quantity of gas evolved depends uponconditions of liberation.

There are two basic types of gas liberation: Flash &Differential.

3

Flash & Differential Liberation

* In flash liberation the pressure is reduced by a finiteamount and after equilibrium is established the gas isbled off, keeping the pressure constant.

• In differential liberation the gas evolved is removedcontinuously from contact with the oil. The liquid is inequilibrium only with the gas being evolved at a givenpressure and not with the gas evolved over a finitepressure range. It is apparent that a series of flashliberations with infinitely small pressure reductionsapproaches a differential liberation.

Differential liberation is of constant volume and changingcomposition and flash liberation is of constantcomposition & volume.

4

Typical plot of ‘r’ versus ‘P’ showing differencesobtained by flash & differential liberation of gas.Two methods of liberation gives different results for ‘r’ as shown above, thevalues of ‘r’ for flash liberation are higher for a given pressure.It is difficult to say which type of liberation is operative in a reservoir & in allprobability both occur simultaneously.

5

SEPARATOR

• used primarily to separate a combined liquid-gas well stream into components that are relatively free of each other. The name Separator usually is applied to the vessel used in the field to separate oil & gas coming directly from an oil or gas well, or group of wells.

• may be either 2-phase or 3-phase. - Two- phase separators remove the total liquid from the gas- Three phase separators also remove free water from hydrocarbon liquid.

6

TYPES OF SEPARATORS

• Scrubber:

a type of separator which has been designedto handle flow streams with unusually highgas to liquid ratios. These are commonly usedin connection with dehydrators, extractionplants, instruments, or compressors forprotection from entrained liquids.

7

TYPES OF SEPARATORS ……..contd.

Knockout:Knockouts are also are separators & fall in two categories:- free water & - total liquid knockoutsFree water knockout is a vessel used to separate free water from a

combined gas, hydrocarbon liquid and water stream. The gas &hydrocarbon liquid usually are allowed to leave the vessel togetherthrough the same outlet to be processed by other equipment. Thewater is removed for disposal. A free water knockout can be utilizedat either high or low pressure.

Total liquid knockout is normally used to remove liquids from a highpressure gas stream (3,000 psig & above ). This vessel usually isused with a cold separation unit.

8


Flash chamber / vessel:

Vessel used as a subsequent stage of separation toprocess the liquid hydrocarbons flashed fromprimary separator. The name is applied to thevessel used as a 2nd stage separator on a coldseparation unit. The vessel is usually of lowpressure design of not more than 125 psigworking pressure. It rarely differs from theconventional low pressure separator.

9


• Expansion vessel:

A vessel into which gas is expanded for cold separationapplication. It is also referred as cold separator or a lowtemperature separator. The vessel differs considerablyfrom the normal separator since it is designed primarilyto handle & melt gas hydrates that are formed byexpansion cooling. In cold separator applications wherea hydrate preventive is used, the design may be veryclose to that of a normal separator. The usual workingpressure of this vessel is in the range of 1,000 to 1,500psig.

10


Filter—( dust scrubber ): Where liquid is present to a fair degree in a gas stream, theconventional oil & gas separator will remove any solid particles instream. The liquid acts to trap solids in the mist extractor (orcoalescer) and other sections of separator. It then serves as amedium to flow the solids out of the vessel.When the gas is dry, there are still solid particles present tointerfere with some phases of gas transmission and distribution.The vessel designed to remove these solids is called a filter or dustscrubber. The filter normally uses a dry filter pack to trapundesirable particles. These filter packs require periodic removal forchanging or cleaning.

Dust scrubber uses an oil bath (or similar liquid bath) to trap the dustparticles. Operation then is quiet similar to a conventionalseparator.

11

Typical Filter Separator

12

Maximum Allowable Working Pressure (MAWP):

Maximum pressure, permissible by ASME Code,at the top of the separator in its normal operatingposition for a designated temperature.

Operating Pressure:

Pressure in the vessel during normal operation.The operating pressure shall not exceed theMAWP, and is kept at a level below the setting ofthe pressure relieving device to prevent theirfrequent opening.

13

SEPARATION MECHANISMS• Separation works on specific temperature &

pressure

• Employs one or more mechanisms:

- Gravity Settling

- Centrifugal Force

- Baffling / Impingement

- Electrostatic / Sonic Precipitation

- Filtration

- Adhesive Separation

- Adsorption

- Heat / Thermal

- Chemical

14

PHASE SEPARATION

• Two Phase:

Gas & Liquid (Oil + Water)

• Three Phase:

Gas, oil & Water

15

Components / Sections of a Separator

• Primary Separation Section

• Liquid Accumulation Section

• Secondary / Gravity Settling Section

• Mist Extraction / Coalescing section

16

Primary Separation Section• Separating bulk of liquid from well stream

• Remove quickly liquid slugs & large droplets ofliquid from gas stream to

- minimize turbulence

- re-entrapment of liquid particles

• Accomplished by

- use of a tangential inlet

- Diverter baffle

Centrifugal force or abrupt change in direction throwsmajor portion of entrained liquid from the gas stream

18

Liquid Accumulation Section

• For receiving & disposing the liquids collected

• Must have sufficient volume to handle liquidsurges

• Room is provided for installation of “LevelControl Device” regulated by a float and acontrol valve

• Provides retention time to let entrained gasesevolve out of oil & rise to vapor space

20

Secondary / Gravity Settling Section• For removing the smaller liquid droplets

• Principle is gravity settling from gas streamrequiring minimum of turbulence

• Straightening vanes provide uniform gas flowthroughout the section

• Vanes also act as droplet collectors/coalescers& their use reduces the distance of a dropletto fall and to be removed from gas stream byfalling into the gas liquid interface

21

Defoaming / Coalescer Plates

22

Mist Extraction / Coalescing section• For the removal of entrained droplets too small to

settle by gravity• entrained droplets are those which are carried when

the vapor velocity is greater than the settling velocity ofdroplets

• Uses elements of vanes, wire-mesh or plates tocoalesce & remove very small droplets of liquid in finalseparation i.e. the gas before leaving the separator

Pressure in the separator is maintained by pr. Controllerwhich senses the changes in pr. & signals to PCV toopen / close. By controlling the rate of gas dischargefrom the vapor space of separator the pr. is maintained

23

Mist Extraction / Coalescing section

24

VESSEL INTERNALS

DISH DEFLECTOR :

The dish deflector is saucer-shapped dish. The wellstream mixture hits it. There is a sudden,

rapid change in the direction and velocity of the mixture. The mixture splashes back against the

curved end of the tank. Gas fumes and mist rise to the top of the tank. Liquids fall to the bottom.

Thus, you get initial separation.

A dish deflector is preferred over angle or cone type deflectors for one good reason. Because it

is smooth & round and creates less disturbance, thus cutting down on re-entrain ment of gas in

the liquid mixture.

CYCLONE INLET :

Used normally where there is a lot more gas than liquid in the mixture coming into the tank. The liquid usually appears in slugs. The slugs gush into a circular enclosure. They are diverted

around the sides, at high velocity. Centrifugal action separates the liquids which, being heavier,

fall to the bottom. Gases escape through an opening in the top of the deflector. Liquids are

rushed to the liquid area quickly, reducing reentrainment tendencies.

With the cyclone deflector, a weir or dam just b elow the deflector is often installed. The weir has

a small port located near the bottom of the vessel. As liquid is trapped behind the weir, it moves

into the main vessel only as fast as the small port allows it to, Thus, there is no overload on the

liquid level controls at the far end of the vessel, and flooding of the mist extractor section is

eliminated.

GAS STRAIGHTENERS

After gas leaves the initial separation area, it must be straightened to remove turbulence in the

gas stream.

Straightening vanes are vertical plates, running lengthwise in the vessel. They extend down into

the tank to a point just above the liquid level.

Gas enters the vanes, an area of controlled, one-direction movement. This reduces turbulence.

And the reduction in turbulence allows the highest efficiency in recovery of liquids. This is

because liquids tend to fall out naturally, through gravi ty, when the gas stream is in a non-

turbulent state.

25

SETTLING BAFFLES :One function of a separator is to slow down and smooth out the mixture flow. then, natural separation can take place.Liquids are retained in the vessel by liquid level controls for a sufficient length of time to allo w natural separation to take place. In applications that warrant steps to prevent gas eddies from entering the liquid area, horizontal plates or baffles are also placed in precise locations above the expected liquid levels. These baffles are flat with lip edges. They are used to keep gas from creating surface turbulence and reentering the liquid stream at the surface of the liquid mixture.The design and placement of these baffles is vital to efficient settling. That is why they are so carefully engineered, designed to the individual well stream, the separator handles.

LIQUID LEVEL CONTROL :

Liquids must stay in the tank long enough for full, natural separation. So, exit from the tank is

controlled. Liquid level controllers maintain the height of the liquid level. When the level reache s

a pre-determined point, the controllers dump excess into the outlet lines.

These control are usually engineered to be easily adaptable to a wide range of conditions. For

instance, over a period of time the amount of oil, gas and water in the well stream may change.

The controls can be adjusted to var y the level at which liquids are dumped, up to the height of

the permanent gas treatment components. This allows flexibility for liquid-gas ratios other than

originally specified.

ANTI-VORTEX LIQUID DRAW OFF

This is, simply, a horizontal pipe extending lengthwise into tank. It is

slotted along its lower diameter, and along its length. This allows liquid

to be withdrawn over a larger area at lower velocities. So, no vortexes.

This is a plate of steel welded over the outlet. It breaks the outlet-stream

into two parts. These plates are used in slow-moving streams, where

vortexing is less of a problem.

26

MIST EXTRACTION SECTION :

Knitted wire mesh mist extractor is able to limit liquid carryover to 1/10 gallon per million cubic feet of gas on all particles 10 microns and larger.

After the gases leave the straightening vanes, there may still be liquid droplets-very tiny-in the gas stream. There are two basic processes used to remove these liquid droplets.

The gas stream, moving rapidly, strikes against and object. Gas is diverted to left or right. Liquids push forward and impinge upon the object. These are of stainless steel knitted wire mesh mist extractor designed to exacting specifications. It is placed to fill the upper part of the tank. All gas moves through it; liq uid impinges within it, and coalesces into large droplets which fall to bottom of tank.

Where there is slight foaming action, a second extractor is installed behind the first.

IMPINGEMENT :

COALESCENCE

high paraffinic content

Gas is led parallel to a baffle already wet with oil. The wet surface

acts as a magnet. It attracts tiny droplets which coalesce on its surface and drain to the bottom of the tank.Arch plates-curved plates of steel are used. They are curve to

match the diameter of the tank. Each plate, gradually diminished in diameter, is placed within the others in exacting relationships. With this design feature, maintenance problems leading to down

time are greatly reduced in separation processes where is involved. Arch Plates are less likely to

become clogged by solid particle buildup. These plates may be

complete circles or semi-circular, depending on quantity of liquid and the tank area required to contain it. Liquids in gas flowing between the arch plates coalesce by molecular attraction. Thus, the gas is stripped of liquid droplets. In many separators a baffle is

welded horizontally across the front of the gas outlet, reversing gas flow direction, as a final mist extraction step.

VERTICAL

SEPARATOR

27

CLASSIFICATION OF SEPARATORS

• VERTICAL SEPARATOR

• HORIZONTAL SEPARATOR

- SINGLE TUBE (ST)

- DOUBLE TUBE (DT)

• SPHERICAL SEPARATOR

28

API-12J

VERTICAL 2 PHASE SEPARATOR HORIZONTAL 2 PHASE SEPARATOR

29

API-12J

HORIZONTAL 2 PHASE DOUBLE BARREL SEPARATOR30

API-12J

SPHERICAL 2 PHASE SEPARATOR31

LOCATION OF DIFFERENT SECTIONS / COMPONENTS

Separator Primary Separation Section

Secondary Separation Section

Mist Extraction / Coalescence Section

Liquid Accumulation Section

Vertical MiddleUpper

Full diameter Extreme top Bottom

Horizontal•ST•DT

InletInlet

Half sectionFull section

Opposite endOpposite end

Lower 1/3 to ½Lower ½ to full

Spherical MiddleUpper

Full Section Extreme top Bottom

32

COMPARISON OF DIFFERENT TYPE OF SEPARATORS

Vertical:Advantages:• Can process large quantity of mud & sand• Can handle more oil per unit gas• Has good surge handling capacity• Liquid level can be varied moderately. Useful on G.L. wells & wells having large

amount of liquids• More space saving• Less tendency of re-vaporization of liquid

Disadvantages:• Difficult to mount on skid• Can’t be easily transported• Handles less gas for certain investment hence not economical• Makes top mountings e.g. safety valves etc. difficult to reach & service• Requires larger diameter for a given gas capacity

…..contd.

33

Horizontal:

Advantages:* Economical for processing large volumes because it has large

capacity

* More true in case of DT where the upper compartment is free forgas

• ST can be easily transported

• Better for foaming crudes because of larger surface area

• For a given gas capacity diameter is smaller than vertical

• More settling area when two liquids are present

Disadvantages:• Can’t handle streams having more sand or mud

• Difficult to wash clean & wax removal

• Liquid level is more critical than vertical

……….contd.

34

Spherical:

Advantages:

• Compact & easy to maintain and can be stacked

• Good separation capacity & better liquid handling

• Most economical for HP single well installations

• Owing to easier mountings suitable for testing wells

Disadvantages:

• Limited surge capacity

• Uneconomical for large gas capacity

• Liquid level control is critical

35

FACTORS AFFECTING SEPARATIONOperating Pressure:• Dependent on both FTP & GOR• Change in pressure affects both the liquid & gas densities

- in the allowable velocity- in actual flowing volumes

Net effect: Increase in pr. is an increased gas capacity of the separator in scf/cm

Temperature:• Affects gas-liquid capacities only as it affects the actual flowing volumes &

densitiesNet effect: increase in temperature is decrease in capacity

Temperature control usually involves cooling as well stream flow temperature aregenerally above the optimum separation temperature. Expansion in the coolingsystem is widely used because HP gas is becoming more common & little capitaloutlay is required.

36

Gas & Liquid Densities:

• Efficiency of separation varies with gas & liquid densities• Separator operating at constant temperature, pressure & well

stream composition has a gas capacity proportional to√[(Pl – Pg) / Pg]

• Maximum gas velocity for the separation of liquid particles ofcertain diameters is based on the physical properties of L&G.

• Particle falling under action of gravity accelerate until thefriction on the particle due to collision with the gas equals,the particle will fall at a constant rate called ‘Settling Velocity’.This is used to determine the time needed for a particle to falla given distance

• Particles smaller than 2 micron in air are often considered a‘permanent suspension’

• Particle diameters in the range of 0.075 to 10 micron arecalled ‘mist’

37

Drop Size:• Purpose of gravity separation section (GSS) is to condition the gas for final

treatment in mist extractor• Field experience indicates, if 100 micron drops of oil are removed in GSS then

the mist extractor will not be flooded & will be able to remove those dropsbetween 10 & 100 micron size

• Gas capacity design equations are based on 100 micron removalGas Scrubbers are designed for removal of 500 microns without flooding their

mist extractors. Examples of such vessels are: Fuel gas scrubbers; compressorsuction scrubbers; contact tower etc.

Flare or vent scrubbers are designed to keep large slugs of liquid fromentering the atmosphere through vent or relief systems. In the vent system gasis directly discharged to atmosphere for removal of 400 to 500 micron dropletsin GSS as per the guidelines for refinery flare. Usually a mist extractor is notinstalled because of possibility that it may plug creating a safety hazard.

Flare Systems where gas is discharged through a flame, there is possibility ofthat burning liquid droplets could fall to floor before being consumed. Onoffshore platforms many operators include mist extraction section (MES) as anextra precaution against a falling flame. Use of MES requires to provide safetyrelief protection around it, in the event it gets plugged.

38

Retention Time:• Defined as the average time a molecule of liquid is retained in the vessel

assuming plug flow.• It is thus the volume of liquid storage in the vessel divided by the liquid flow

rate.• It is affected by composition, foaming tendency, presence of solids &

emulsions etc.For most applications retention times between 30 secs. & 3 minutes have been

found to be sufficient. For foaming crudes, retention times up to four timesthis amount may be needed. For chemical reactors like ‘Water DeoxygenatingTowers’ it is kept about 3 to 5 minutes.

As per API – 12JTypical retention time Mins.• Natural gas-oil 2 – 3• Lean oil - surge tank 10 – 15• Fractionation feed tanks 8 – 15• Refrigerant surge tanks 4 – 7• Refrigerant economizers 2 – 3

………contd.

39

Gas – Oil SeparatorsRetention Time – 2 phase

(No foaming, wax deposit & slug flow)

Oil relative density Ret. Time (mins.)

Below 0.85 (API° > 35) 1

– 0.93 (API ° 20 – 30) 1 to 2

0.85 – 1.0 (API ° 10 – 20) 2 to 4

Retention Time – 3 phase

API ° > 35 3 to 5

below 35 ° & Sep. temp.

100 ° + F 5 to 10

80 ° +F 10 to 20

60 ° +F 20 to 30

40

Initial Separator pressure (Pi):• Higher the pressure at which initial separation occurs more liquid will be

obtained

• This liquid contains some lighter components that vaporize in STdownstream the separator & be lost to the gas phase at ST

• If Pi is too low much of these light components will be stabilized into theliquid & will be lost in the gas phase

41

Three Phase Oil , Gas & Water Separation

When a mix of oil & water areallowed to settle, a layer of relativelyclean free water will appear at thebottom and its growth is timedependant as shown. After a periodof time, ranging anywhere between3 to 20 minutes, the change in waterheight shall be negligible. Waterfraction obtained from “gravitysettling” is called ‘free water’. This isnormally beneficial to separate freewater before treating remaining oil &emulsions.

3-ph. Separators, commonly called“Free-water Knockouts” & are usedto separate & remove any free waterphase that may be present. Becauseflow enters 3-ph separator directlyfrom:

•Producing well

• or high pr. designed operatingvessel to separate gas flashes fromliquid as well as oil & water

42

METERING SEPARATORS (MS)

• Separation of well fluids to O, G & W and metering can be accomplished inone vessel

• These are metering separators & are 2–phase and 3-phase types

• Variations in internals makes them suitable for accurately meteringfoaming oil & heavy viscous oil and are classified as “foaming oil type” &“heavy viscous crude type”

• Metering of liquid is accomplished by accumulation, isolation anddischarge of given volumes in a metering compartment in the lowerportion of vessel

• Foaming oil type utilizes a hydrostatic head level controller to accomplishaccurate measurement on the basis of weight rather than volume

• Heavy viscous type utilizes pressure flow into & out of vessel and does notrely on gravity flow

Such units are furnished with ‘hydrostatic – head liquid – level controls for

metering foaming oil or float operated for non foaming oils

43

Controlling 3-Phase Separation

44

Trailer - Mounted Three-Phase Well Tester with Batch-Type Meters

45

OPERATION PROBLEMSFOAMING:• Can increase dramatically amount of liquid carry-over with gas

• 3 fold problem:

- mechanical control of liquid level

- has a large volume to weight ratio whereby occupying much of the vessel spacefor liquid accumulation & gravity settling section

- in foam bank, it is impossible to remove separated gas or degassed oil withoutentraining some of the foaming material in liquid or gas outlets

Lab. tests on foaming & foam stability are conducted when new fields are discovered andnew facilities are designed

When foaming is ‘potential problem:

- Antifoam additives injection be provided upstream of separator (lab. tests)

- Increase retention time within reasonable limits

- Install cyclonic device as fluid inlet distributor

- Provide vane type of mist extractor upstream of gas outlet nozzleWhile designing/selecting a separator, provide sufficient capacity to handle anticipated production

without use of anti-foam additive. Once operations are on , use of anti-foam additive may allow more

throughput than design capacity. …………contd.

46

OPERATION PROBLEMSEmulsions – Water Carry Through: troublesome in operations

- Over a period of time emulsified materials with other impurities accumulate & foam at inter-phaseof W&O which affect the separation efficiency

- Addition of heat & chemicals often minimizes this difficulty- To overcome the problem:

* add de-emulsifier upstream of separator* provide coalescing devices* when necessary, provide heating coil to improve water settling & break of emulsion ofwaxy crudes (e.g. Mumbai High Crude)

Solid Deposits:• Sand carryover from reservoirs• Salt deposits from formation waterTroublesome;- Can cause cut-out of valve trims- Plugging of internals- Accumulations at bottom whereby reducing capacity of LAS & causing corrosionTo overcome:- provide water-jets to fluidize & prevent accumulation- Design outlet circuits considering accumulations and corrosion- Provide anti-deposit additive injection after lab. tests- Provide soft water injection facilities for water soluble salt deposits

……….contd.

47

OPERATION PROBLEMS

Carry Over & Blowby:Carryover occurs when free liquid escapes gas phase- Can indicate high liquid level- Damage to vessel internals- Plugged liquid outlets or exceeding the design rate of vessel (e.g. foam,

improper design)Amount of liquid carry over coming from droplets larger in size than 10 micron is

generally less than 0.1 gallon / MSCF

Blowby occurs when free gas escapes with liquid phase and indicates- low liquid level- Vortexing- Level control failure

48

TYPICAL PROBLEMS SOLVED BY OIL FIELD SEPARATORS

PROBLEM :

CONDITIONS :

ELEMENTS USED :

Two-phase, primary separation of

light crude production.

100: 1 GOR, 50 psi W.P.,

90 F, 10,000 SCFD, Oil Gravity : 40 API, Gas

Gravity : 0.8

Dish Def lector,

Straightening Vane Section, Anti-Vortex Liquid

Withdrawal.

0 0

PROBLEM :

CONDITIONS :

ELEMENTS USED :

Two-phase, primary separation of

light crude separation.

1000 : 1 GOR, 100 psi

W.P.,100 F, 10 MMSCFD, 10,000 BOPD, Oil

Gravity : 30 API, Gas Gravity : 0.75

Cyclone Inlet, Mist

Extractor Section, Half Diameter Arch Plates,

Anti-Vortex Liquid Withdrawal.

0

0

49

PROBLEM :

CONDITIONS :

ELEMENTS USED :

Two-phase Primary Separation;

waxy gas production.

10,000 : 1 GOR, 1000 psi W.P.,

80 F, 10 MMSCFD, 1000 BOPD, Oil Gravity :

70 API, Gas Gravity : 0.7

Dish Deflector, Two Arch

Plates, Anti-Vortex Liquid Withdrawal.

0

0

PROBLEM :

CONDITIONS :

ELEMENTS USED :

Separating liquid mist and liquid

slugs in a gas stream.

1000 psi W.P., 90 F, 100.00

MMSCFPD, Oil : in mist and slug form. Gas

Gravity : 0.75

Cyclone Inlet, Mist

Extractor Section (Modified for Greater Area)


0

50

PROBLEM :

CONDITIONS :

ELEMENTS USED :

Two-phase Separation for

recycling in a gas condensate field.

20,000 : 1 GOR, 1000 psi W.P.,

100 F, 10 MMSCFD, 500 BOPD, Oil Gravity :

70 API, Gas Gravity : 0.7

Dish Def lector,

Straightening Vane Section, Mist Extractor and


0

0

PROBLEM :

CONDITIONS :

ELEMENTS USED :

An after scrubber needed

downstream of a condensate separator that is

prone to clog up, due to paraffin, and carry over.

500,000 : 1 GOR, 1200 psi

W.P., 90 F, 150 MMSCFD, Condensate

Gravity : 0.50 API, Gas Gravity : 0.65

Dish Deflector, Full

Diameter Arch plate, Anti-Vortex Liquid

Withdrawal.

0

0

51

Some Typical Filter Separator-Scrubbers

52

Centrifugal and Combination Centrifugal - Impingement Separators

53

Centrifugal and Combination Centrifugal - Impingement Separators

54

O & M OF SEPARATORS

• Periodic Inspection:In oilfield operations, it is normal practice to clean andinspect all pressure vessels periodically for corrosionand erosion. This practice avoids hazardous conditionsfor operating personnel and surrounding equipments.OMR-84 recommends hydraulic test at a pressure atleast one and half times of maximum permissibleworking pressure. This test is required after everyrenewal or repair and in any case at intervals of notmore than three years. The results of these tests shallbe recorded in the registration book of the vessels andalso marked on the body of the vessel.

55

• Installation of Safety Devices:

All the safety relief devices should be installed asclose to the vessel as possible and in suchmanner that the reaction force from exhaustingfluids will not break off, unscrew, or otherwisedislodge the safety device. The discharge fromsafety devices should not endanger personnel orother equipment. As per OMR-84, this deviceshall be set to open at a pressure not exceeding10 percent, above the maximum allowable W.P. &shall be tested once is every six months andrecorded in the book at installation.

56

A. Safety Heads (Rupture Disks)

The discharge from a safety head should be open andwithout restriction. The discharge line from a safetydevice should be parallel to a vertical separator andperpendicular to a horizontal one; otherwise theseparator may be blown over by the reaction forcefrom exhausting fluids. A valve should not be usedbetween the safety head and the separator becausesomeone may inadvertently close it. Water should notbe allowed to accumulate on top of the rupturediaphragm. It could freeze and alter the rupturecharacteristics of the diaphragm. (Operation of an oiland gas separator without a properly sized andinstalled safety head or rupture disk is notrecommended.)

57

B. Pressure Relief Valves:

Relief valves may corrode and leak or may “freeze” in theclosed position. They should be checked periodicallyand replaced if not in good working condition.Discharge lines, especially those on full-capacity reliefvalves, should be such that reaction force fromdischarge will not move the separator. Safety reliefvalves with “try” handles are recommended for generaluse (OMR – 84).

DO NOT USE ANY TYPE OF VALVE UPSTREAM OF ANY

SAFETY DEVICE.

58

Mist Extractors:

Some mist extractors in oil and gas separators require a drain or“liquid down-comer” to conduct liquid from the mist extractor tothe liquid section of the separator. This drain will be a source oftrouble when pressure drop through the mist extractor becomesexcessive. If the pressure drop across the mist extractor,measured in inches of oil, exceeds the distance from the oil levelin the separator to the mist extractor, the oil will flow from thebottom of the separator up through the mist-extractor drain andout with the gas. This condition may be aggravated by partialplugging of the mist extractor with paraffin or other foreignmaterial. This explains why some separators have definite fixedcapacities that cannot be exceeded without “liquid carryover”through the gas outlet, and it also explains why the capacities ofsome separators may be lowered with use. In recent years,separators of advanced design have utilized mist extractors thatdo not require drains or down comers. These designs eliminatethis source of trouble.

59

Low Temperature:Separators should be operated above hydrate-formationtemperatures. Otherwise hydrates may form in the vessel andpartially or completely plug it. This reduces capacity of theseparator and, in some instances when the liquid or gas outlet isplugged or restricted, will cause the safety valve to open or thesafety head to rupture.

Corrosive Fluid:A separator handling corrosive fluid should be checked periodicallyto determine if remedial work is required. Extreme cases ofcorrosion may require a reduction in the rated working pressure ofthe vessel. Periodic hydrostatic testing is recommended, especiallyif the fluids being handled are corrosive. Expendable anodes can beused in separators to protect them against electrolytic corrosion.Periodic inspections as per OMR- 84 are to be carried out asexplained above.

60

Paraffin:A separator handling paraffin-base oil may need to besteamed periodically to prevent plugging and a resultantdecrease in capacity. This reduction in capacity oftenresults in liquid carryover in the gas or discharge of gas withthe liquid.

High-capacity Operation:Where separators are operating near or at their maximumrated capacity, they should be checked carefully andperiodically to determine if acceptable separation is beingaccomplished.

Pressure Shock Loads:Wells should be switched in and out of the separatorslowly. Fast opening and closing of valves cause damagingshock loads on the vessel and its component.

61

Throttling Discharge of Liquid:Throttling discharge of small volumes of liquid fromseparators normally should e avoided. Throttling causeserosion or wire drawing of the inner valves and seats of theliquid-dump valves and may erode the dup-valve bodies tothe extent that they are in danger of bursting at ratedworking pressures.However, throttling discharge may be necessary because ofprocessing units, such as lower-pressure separators orstabilization units, downstream of the separator.

Pressure Gauges:Pressure gauges and other mechanical devices onseparators should be checked for accuracy at regularintervals and records maintained as per OMR-84. Isolatingvalves should be used so gauges can be removed for repairsor replacement.

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Gauge Cocks and Glasses:Gauge cocks and gauge glasses should be kept clean so that the liquid level in the gauge glass reflects the true level in the Separator at all times. Flushing of the gauge glass or cleaning by use of special swabs is recommended.

Cleaning of Vessels:It is recommended that all separator vessels be equipped with man ways, cleanout openings, and/or washout connections so the vessels can be drained and cleaned periodically. Larger vessels can be equipped with man ways to facilitate cleaning them. Smaller vessels can be equipped with hand holes and/or washout connections so they can be easily cleaned or washed out periodically.

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STAGE SEPARATION

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STAGE SEPARATION OF OIL & GAS

• Accomplished with a series of separators operating atsequentially reduced pressures

• Liquid is discharged from a higher-pressure separatorinto the next lower-pressure separator.

• The purpose is to obtain maximum recovery of liquidhydrocarbons from the well fluid and to providemaximum stabilization of both the liquid and gaseffluent.

Two processes of liberating gas (vapor) from liquidhydrocarbon under pressure

• flash separation (vaporization) • differential separation

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Flash separation: Accomplished when pressure is reduced on thesystem with the liquid and vapor (gas) remainingin contact, that is, the vapor (gas) is not removedfrom contact with the liquid as reduction inpressure allows the vapor (gas) to come out ofsolution. This process yields the most vapors (gas)and the least liquid.

Differential separation:Accomplished when the vapor (gas) is removedfrom contact with the liquid as reduction inpressure allows the vapor to come out ofsolution. This process yields the most liquid andleast vapor (gas).

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In a multiple-stage separator installation bothprocesses of gas liberation are obtained. Whenthe well fluid flows through the formation,tubing, chokes, reducing regulators, and surfacelines, pressure reduction occurs with the gas incontact with the liquid. This is flash separation.

When the fluid passes through a separator,pressure reduction is accomplished; also, the oiland gas are separated and discharged separately.This is differential separation. The more nearlythe separation system approaches truedifferential separation from producing formationto storage, the higher the yield of liquid will be.

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An “ideal” oil and gas separator, from thestandpoint of maximum liquid recovery, is oneso constructed that it reduces the pressure ofthe well fluid from the wellhead at theentrance of the separator vessel to, or near,atmospheric pressure at the discharge fromthe separator. The gas and / or vapor isremoved from the separator continuously assoon as it is separated from the liquid. This isknown as differential vaporization orseparation.

However, such an arrangement is not practical.

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Some of the benefits of an “ideal” separator may be obtainedby use of multiple-stage separation. The number of stagesdoes not have to be large to obtain an appreciable benefit,as can be seen from the table below :

Number of stages Approximate % approach of separation to differential vaporization

2 03 754 905 96

6 98 1/2

Economics usually limits the number of stages of separationto three or four, but five or six will pay out under favorableconditions. Seven stages have been used on large volumesof oil, but such installations are rare.

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Ratios of operating pressures between stage in multiple-stage separation can be approximated from the following equation:

n P1

R = √ ---Ps

P1

P2 = --- = Ps Rn-1

R

P2

P3 = --- = Ps Rn-1

R

P1 P2 Pn

Where , R = stage pressure ratio = = ----- = -------- = ……. -------P2 P3 Ps

n = number of inter-stages (number of stages – 1)P1 = first-stage separator pressure, psiaP2 = second-stage separator pressure, psiaP3 = third-stage separator pressure, psiaPs = storage-tank pressure, psia

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Equilibrium flash calculations should be made forseveral assumed conditions of pressures andtemperatures to determine the conditions that willyield the most stock-tank liquid. However, the aboveequation will give a practical approximation that can beused when no other information is available.

Two-stage separation is normally considered to beobtained when one oil and gas separator is used inconjunction with a storage tank. Three-stageseparation is obtained when two separators are used inseries at different pressure, in conjunction with storagetank. Since gas may continue to separate or “weather”from oil in storage tanks, the storage tank is consideredas a “stage” of separation. Slide - 64 showsschematically a four-stage separator installation.

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Economic considerations of stage separation of Oil & GasThe extent of application of stage separation on economicconsideration will depend upon two principal considerations:* The terms of the gas sales contact* The price structure for the gas and liquid

hydrocarbons.

If gas is sold on volume only, it will usually be desirable toremove the condensable vapors from the gas and add them tothe liquid increase its sales price (more API greater revenue).

If, on the other hand, the liquid is sold on the basis of volumeonly, it may be desirable to leave the condensable vapors inthe gas.

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Other considerations of stage separation:

* Physical and chemical characteristics of the well fluid

* Flowing wellhead pressure and temperature

* Operating pressures of available gas-gathering systems

* Conservation features of liquid-storage facilities

* Facilities for transporting liquids.

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The point of diminishing returns in stageseparation is reached when the cost of additionalstages of separation is not justified by increasedeconomic gains. The optimum number of stagesof separation can be determined by field testingand/or by equilibrium calculations based onlaboratory tests (PVT) of the well fluid.

Equilibrium flash calculations indicate accuratelythe gas and liquid from oil and gas separators ifthe composition of well fluid is known.

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SAFETY FEATURES OF OIL & GAS SEPARATORSOil & Gas separators are installed on offshore platforms/ on land oil installations and invariably placed in closeproximity to other equipments. In order to preventdamage to surrounding equipment and personnel inevent of failure of the separator, its controls oraccessories, following safety features are provided onO&G separators.

* High- and low- liquid controls normally are float-operated pilots that actuate a valve on the inlet to theseparator, open a bypass around the separator, sound awarning alarm, or perform some other pertinentfunction to prevent damage that might result from highor low liquid levels in the separator.

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High- and lowpressure controls are installed onseparators to prevent excessively high or lowpressures from interfering with normaloperations. These high- and low- pressurecontrols can be mechanical, pneumatic, orelectric and can sound a warning, actuate a shut-in valve, open a bypass, or perform otherpertinent functions to protect the separator andsurrounding equipment.

High and low temperature controls may beinstalled in or on the separator to shut in the unit,open a bypass or sound a warning shouldtemperature in the separator become too high ortoo low.

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Safety relief valves is a spring-loaded safety relief devicewhich is usually furnished with and installed on all oil andgas separators. They normally are set at the designpressure of the vessel. Safety relief valves serve primarily aswarning devices and inmost instances are too small tohandle the full rated capacity of the separator. Full capacitysafety valves can be fitted and are recommended when nosafety head (rupture disk) is used on the separator.

Safety head or rupture disk is a device containing a thinmembrane that is designed to rupture when pressure inthe vessel reaches a predetermined value. This is usuallyfrom 11/4 to 11/2 times the design pressure of the vessel.The safety head is usually selected so that it will notrupture until after the safety relief valve has opened andsafety relief valve is incapable of preventing excessivepressure buildup in the separator. (Not preferred now)

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SAFETY ANALYSIS OF PRESSURE VESSELS

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SEPARATOR SELECTION(RULE OF THUMB)

• Find one each of various size & shape fitting the G&L requirement

• Compare costs

• Determine which shape fits the particular installation best e.g. space, mounting, ease of access and external maintenance

• Determine if unusual well conditions (foam, sand etc.) wouldmake the vessel selected difficult to operate or maintain

• Make certain that there is no design requirement (heatingcoils for paraffin or hydrate or 3-phasing for water removaletc.) that would make the shape selected expensive to use ordifficult to operate

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Separation of Oil, Gas

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