SEPARATION OF OIL, GAS & WATER
1
GAS SOLUBILITY (r) Defined as the no of cubic Feet of gas measured at standard conditions which are in solutions in one barrel of STO at reservoir pr. & temp.
Typical ‘gas solubility curve’ as a function of pressure is shown for a “Saturated Crude Oil” 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 remains constant at ‘r’ but at pressures below P gas is 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 gas solubility is defined as the number of cubic feet of gas measured at std. conditions which are in solutions in one barrel of S.T.O. at reservoir temp. & pressure. If the pressure is released from a sample of reservoir crude oil the quantity of gas evolved depends upon conditions 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 finite amount and after equilibrium is established the gas is bled off, keeping the pressure constant. • In differential liberation the gas evolved is removed continuously from contact with the oil. The liquid is in equilibrium only with the gas being evolved at a given pressure and not with the gas evolved over a finite pressure range. It is apparent that a series of flash liberations with infinitely small pressure reductions approaches a differential liberation. Differential liberation is of constant volume and changing composition and flash liberation is of constant composition & volume. 4
Typical plot of ‘r’ versus ‘P’ showing differences obtained by flash & differential liberation of gas. Two methods of liberation gives different results for ‘r’ as shown above, the values 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 all probability 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 designed to handle flow streams with unusually high gas to liquid ratios. These are commonly used in connection with dehydrators, extraction plants, instruments, or compressors for protection from entrained liquids.
7
TYPES OF SEPARATORS
……..contd.
Knockout: Knockouts are also are separators & fall in two categories: - free water & - total liquid knockouts Free 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 together through the same outlet to be processed by other equipment. The water is removed for disposal. A free water knockout can be utilized at either high or low pressure. Total liquid knockout is normally used to remove liquids from a high pressure gas stream (3,000 psig & above ). This vessel usually is used with a cold separation unit. 8
TYPES OF SEPARATORS
……..contd.
Flash chamber / vessel: Vessel used as a subsequent stage of separation to process the liquid hydrocarbons flashed from primary separator. The name is applied to the vessel used as a 2nd stage separator on a cold separation unit. The vessel is usually of low pressure design of not more than 125 psig working pressure. It rarely differs from the conventional low pressure separator.
9
TYPES OF SEPARATORS
……..contd.
• Expansion vessel: A vessel into which gas is expanded for cold separation application. It is also referred as cold separator or a low temperature separator. The vessel differs considerably from the normal separator since it is designed primarily to handle & melt gas hydrates that are formed by expansion cooling. In cold separator applications where a hydrate preventive is used, the design may be very close to that of a normal separator. The usual working pressure of this vessel is in the range of 1,000 to 1,500 psig. 10
TYPES OF SEPARATORS
……..contd.
Filter—( dust scrubber ): Where liquid is present to a fair degree in a gas stream, the conventional oil & gas separator will remove any solid particles in stream. The liquid acts to trap solids in the mist extractor (or coalescer) and other sections of separator. It then serves as a medium to flow the solids out of the vessel. When the gas is dry, there are still solid particles present to interfere with some phases of gas transmission and distribution. The vessel designed to remove these solids is called a filter or dust scrubber. The filter normally uses a dry filter pack to trap undesirable particles. These filter packs require periodic removal for changing or cleaning. Dust scrubber uses an oil bath (or similar liquid bath) to trap the dust particles. Operation then is quiet similar to a conventional separator. 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 operating position for a designated temperature. Operating Pressure: Pressure in the vessel during normal operation. The operating pressure shall not exceed the MAWP, and is kept at a level below the setting of the pressure relieving device to prevent their frequent 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
17
Primary Separation Section • Separating bulk of liquid from well stream • Remove quickly liquid slugs & large droplets of liquid 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 throws major portion of entrained liquid from the gas stream 18
19
Liquid Accumulation Section • For receiving & disposing the liquids collected • Must have sufficient volume to handle liquid surges • Room is provided for installation of “Level Control Device” regulated by a float and a control valve • Provides retention time to let entrained gases evolve out of oil & rise to vapor space 20
Secondary / Gravity Settling Section • For removing the smaller liquid droplets • Principle is gravity settling from gas stream requiring minimum of turbulence • Straightening vanes provide uniform gas flow throughout the section • Vanes also act as droplet collectors/coalescers & their use reduces the distance of a droplet to fall and to be removed from gas stream by falling 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 of droplets • Uses elements of vanes, wire-mesh or plates to coalesce & remove very small droplets of liquid in final separation i.e. the gas before leaving the separator Pressure in the separator is maintained by pr. Controller which senses the changes in pr. & signals to PCV to open / close. By controlling the rate of gas discharge from 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 the liquid mixture.
ment of gas in
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 nonturbulent 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
VERTICAL SEPARATOR
MIST EXTRACTION SECTION : 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. IMPINGEMENT : 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. 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. Where there is slight foaming action, a second extractor is installed behind the first.
COALESCENCE 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 high paraffinic content 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.
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 SEPARATOR 30
API-12J
SPHERICAL 2 PHASE SEPARATOR
31
LOCATION OF DIFFERENT SECTIONS / COMPONENTS Separator
Primary Separation Section
Secondary Separation Section
Mist Extraction Liquid / Coalescence Accumulation Section Section
Vertical
Middle Upper
Full diameter
Extreme top
Bottom
Inlet Inlet
Half section Full section
Opposite end Opposite end
Lower 1/3 to ½ Lower ½ to full
Middle Upper
Full Section
Extreme top
Bottom
Horizontal •ST •DT Spherical
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 for gas • 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 SEPARATION Operating 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 & densities Net effect: increase in temperature is decrease in capacity Temperature control usually involves cooling as well stream flow temperature are generally above the optimum separation temperature. Expansion in the cooling system is widely used because HP gas is becoming more common & little capital outlay 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 of certain diameters is based on the physical properties of L&G. • Particle falling under action of gravity accelerate until the friction 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 fall a 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 are called ‘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 drops between 10 & 100 micron size • Gas capacity design equations are based on 100 micron removal Gas Scrubbers are designed for removal of 500 microns without flooding their mist extractors. Examples of such vessels are: Fuel gas scrubbers; compressor suction scrubbers; contact tower etc.
Flare or vent scrubbers are designed to keep large slugs of liquid from
entering the atmosphere through vent or relief systems. In the vent system gas is directly discharged to atmosphere for removal of 400 to 500 micron droplets in GSS as per the guidelines for refinery flare. Usually a mist extractor is not installed because of possibility that it may plug creating a safety hazard. Flare Systems where gas is discharged through a flame, there is possibility of that burning liquid droplets could fall to floor before being consumed. On offshore platforms many operators include mist extraction section (MES) as an extra precaution against a falling flame. Use of MES requires to provide safety relief 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 times this amount may be needed. For chemical reactors like ‘Water Deoxygenating Towers’ it is kept about 3 to 5 minutes.
As per API – 12J Typical 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 Separators Retention 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)
Retention Time – 3 phase API ° > 35 below 35 ° & Sep. temp. 100 ° + F 80 ° +F 60 ° +F
2 to 4
3 to 5 5 to 10 10 to 20 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 ST downstream the separator & be lost to the gas phase at ST • If Pi is too low much of these light components will be stabilized into the liquid & will be lost in the gas phase
41
Three Phase Oil , Gas & Water Separation
When a mix of oil & water are allowed to settle, a layer of relatively clean free water will appear at the bottom and its growth is time dependant as shown. After a period of time, ranging anywhere between 3 to 20 minutes, the change in water height shall be negligible. Water fraction obtained from “gravity settling” is called ‘free water’. This is normally beneficial to separate free water before treating remaining oil & emulsions. 3-ph. Separators, commonly called “Free-water Knockouts” & are used to separate & remove any free water phase that may be present. Because flow enters 3-ph separator directly from: •Producing well • or high pr. designed operating vessel to separate gas flashes from liquid as well as oil & water 42
METERING SEPARATORS (MS) • Separation of well fluids to O, G & W and metering can be accomplished in one vessel • These are metering separators & are 2–phase and 3-phase types • Variations in internals makes them suitable for accurately metering foaming oil & heavy viscous oil and are classified as “foaming oil type” & “heavy viscous crude type” • Metering of liquid is accomplished by accumulation, isolation and discharge of given volumes in a metering compartment in the lower portion of vessel • Foaming oil type utilizes a hydrostatic head level controller to accomplish accurate measurement on the basis of weight rather than volume • Heavy viscous type utilizes pressure flow into & out of vessel and does not rely 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 PROBLEMS FOAMING: • •
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 space for liquid accumulation & gravity settling section in foam bank, it is impossible to remove separated gas or degassed oil without entraining some of the foaming material in liquid or gas outlets Lab. tests on foaming & foam stability are conducted when new fields are discovered and new 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 nozzle While 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 PROBLEMS Emulsions – Water Carry Through: troublesome in operations -
Over a period of time emulsified materials with other impurities accumulate & foam at inter-phase of 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 of waxy crudes (e.g. Mumbai High Crude)
Solid Deposits: • Sand carryover from reservoirs • Salt deposits from formation water Troublesome; - Can cause cut-out of valve trims - Plugging of internals - Accumulations at bottom whereby reducing capacity of LAS & causing corrosion To 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 : Two-phase, primary separation of light crude production. CONDITIONS : 100: 1 GOR, 50 psi W.P., 900 F, 10,000 SCFD, Oil Gravity : 40 0API, Gas Gravity : 0.8 E L E ME NT S US E D : Di sh De f l e ct o r, Straightening Vane Section, Anti-Vortex Liquid Withdrawal.
PROBLEM : Two-phase, primary separation of light crude separation. CONDITIONS : 1000 : 1 GOR, 100 psi 0
W.P.,100 F, 10 MMSCFD, 10,000 BOPD, Oil 0 Gravity : 30 API, Gas Gravity : 0.75 ELEMENTS USED : Cyclone Inlet, Mist Extractor Section, Half Diameter Arch Plates, Anti-Vortex Liquid Withdrawal.
49
PROBLEM : Two-phase Primary Separation; waxy gas production. CONDITIONS : 10,000 : 1 GOR, 1000 psi W.P., 800 F, 10 MMSCFD, 1000 BOPD, Oil Gravity : 700 API, Gas Gravity : 0.7 ELEMENTS USED : Dish Deflector, Two Arch Plates, Anti-Vortex Liquid Withdrawal.
PROBLEM : Separating liquid mist and liquid slugs in a gas stream. 0
CONDITIONS : 1000 psi W.P., 90 F, 100.00 MMSCFPD, Oil : in mist and slug form. Gas Gravity : 0.75 ELEMENTS USED : Cyclone Inlet, Mist Extractor Section (Modified for Greater Area) Anti-Vortex Liquid Withdrawal.
50
PROBLEM : Two-phase Separation for recycling in a gas condensate field. CONDITIONS : 20,000 : 1 GOR, 1000 psi W.P., 100 0 F, 10 MMSCFD, 500 BOPD, Oil Gravity : 700 API, Gas Gravity : 0.7 E L E ME NT S US E D : Di sh De f l e ct o r, Straightening Vane Section, Mist Extractor and Anti-Vortex Liquid Withdrawal.
PROBLEM : An after scrubber needed downstream of a condensate separator that is prone to clog up, due to paraffin, and carry over. CONDITIONS : 500,000 : 1 GOR, 1200 psi 0
W.P., 90 F, 150 MMSCFD, Condensate 0 Gravity : 0.50 API, Gas Gravity : 0.65 ELEMENTS USED : Dish Deflector, Full Diameter Arch plate, Anti-Vortex Liquid Withdrawal.
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 and inspect all pressure vessels periodically for corrosion and erosion. This practice avoids hazardous conditions for operating personnel and surrounding equipments. OMR-84 recommends hydraulic test at a pressure at least one and half times of maximum permissible working pressure. This test is required after every renewal or repair and in any case at intervals of not more than three years. The results of these tests shall be recorded in the registration book of the vessels and also marked on the body of the vessel. 55
• Installation of Safety Devices: All the safety relief devices should be installed as close to the vessel as possible and in such manner that the reaction force from exhausting fluids will not break off, unscrew, or otherwise dislodge the safety device. The discharge from safety devices should not endanger personnel or other equipment. As per OMR-84, this device shall be set to open at a pressure not exceeding 10 percent, above the maximum allowable W.P. & shall be tested once is every six months and recorded in the book at installation. 56
A. Safety Heads (Rupture Disks) The discharge from a safety head should be open and without restriction. The discharge line from a safety device should be parallel to a vertical separator and perpendicular to a horizontal one; otherwise the separator may be blown over by the reaction force from exhausting fluids. A valve should not be used between the safety head and the separator because someone may inadvertently close it. Water should not be allowed to accumulate on top of the rupture diaphragm. It could freeze and alter the rupture characteristics of the diaphragm. (Operation of an oil and gas separator without a properly sized and installed safety head or rupture disk is not recommended.) 57
B. Pressure Relief Valves: Relief valves may corrode and leak or may “freeze” in the closed position. They should be checked periodically and replaced if not in good working condition. Discharge lines, especially those on full-capacity relief valves, should be such that reaction force from discharge will not move the separator. Safety relief valves with “try” handles are recommended for general use (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 to the liquid section of the separator. This drain will be a source of trouble when pressure drop through the mist extractor becomes excessive. If the pressure drop across the mist extractor, measured in inches of oil, exceeds the distance from the oil level in the separator to the mist extractor, the oil will flow from the bottom of the separator up through the mist-extractor drain and out with the gas. This condition may be aggravated by partial plugging of the mist extractor with paraffin or other foreign material. This explains why some separators have definite fixed capacities that cannot be exceeded without “liquid carryover” through the gas outlet, and it also explains why the capacities of some separators may be lowered with use. In recent years, separators of advanced design have utilized mist extractors that do not require drains or down comers. These designs eliminate this source of trouble.
59
Low Temperature: Separators should be operated above hydrate-formation temperatures. Otherwise hydrates may form in the vessel and partially or completely plug it. This reduces capacity of the separator and, in some instances when the liquid or gas outlet is plugged or restricted, will cause the safety valve to open or the safety head to rupture.
Corrosive Fluid: A separator handling corrosive fluid should be checked periodically to determine if remedial work is required. Extreme cases of corrosion may require a reduction in the rated working pressure of the vessel. Periodic hydrostatic testing is recommended, especially if the fluids being handled are corrosive. Expendable anodes can be used in separators to protect them against electrolytic corrosion. Periodic inspections as per OMR- 84 are to be carried out as explained above.
60
Paraffin: A separator handling paraffin-base oil may need to be steamed periodically to prevent plugging and a resultant decrease in capacity. This reduction in capacity often results in liquid carryover in the gas or discharge of gas with the liquid. High-capacity Operation: Where separators are operating near or at their maximum rated capacity, they should be checked carefully and periodically to determine if acceptable separation is being accomplished. Pressure Shock Loads: Wells should be switched in and out of the separator slowly. Fast opening and closing of valves cause damaging shock loads on the vessel and its component. 61
Throttling Discharge of Liquid: Throttling discharge of small volumes of liquid from separators normally should e avoided. Throttling causes erosion or wire drawing of the inner valves and seats of the liquid-dump valves and may erode the dup-valve bodies to the extent that they are in danger of bursting at rated working pressures. However, throttling discharge may be necessary because of processing units, such as lower-pressure separators or stabilization units, downstream of the separator. Pressure Gauges: Pressure gauges and other mechanical devices on separators should be checked for accuracy at regular intervals and records maintained as per OMR-84. Isolating valves should be used so gauges can be removed for repairs or replacement. 62
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. 63
STAGE SEPARATION
64
STAGE SEPARATION OF OIL & GAS • Accomplished with a series of separators operating at sequentially reduced pressures • Liquid is discharged from a higher-pressure separator into the next lower-pressure separator. • The purpose is to obtain maximum recovery of liquid hydrocarbons from the well fluid and to provide maximum stabilization of both the liquid and gas effluent. Two processes of liberating gas (vapor) from liquid hydrocarbon under pressure • flash separation (vaporization) • differential separation 65
Flash separation: Accomplished when pressure is reduced on the system with the liquid and vapor (gas) remaining in contact, that is, the vapor (gas) is not removed from contact with the liquid as reduction in pressure allows the vapor (gas) to come out of solution. This process yields the most vapors (gas) and the least liquid. Differential separation: Accomplished when the vapor (gas) is removed from contact with the liquid as reduction in pressure allows the vapor to come out of solution. This process yields the most liquid and least vapor (gas). 66
In a multiple-stage separator installation both processes of gas liberation are obtained. When the well fluid flows through the formation, tubing, chokes, reducing regulators, and surface lines, pressure reduction occurs with the gas in contact with the liquid. This is flash separation. When the fluid passes through a separator, pressure reduction is accomplished; also, the oil and gas are separated and discharged separately. This is differential separation. The more nearly the separation system approaches true differential separation from producing formation to storage, the higher the yield of liquid will be. 67
An “ideal” oil and gas separator, from the standpoint of maximum liquid recovery, is one so constructed that it reduces the pressure of the well fluid from the wellhead at the entrance of the separator vessel to, or near, atmospheric pressure at the discharge from the separator. The gas and / or vapor is removed from the separator continuously as soon as it is separated from the liquid. This is known as differential vaporization or separation. However, such an arrangement is not practical. 68
Some of the benefits of an “ideal” separator may be obtained by use of multiple-stage separation. The number of stages does 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 0 3 75 4 90 5
96
6 98 1/2 Economics usually limits the number of stages of separation to three or four, but five or six will pay out under favorable conditions. Seven stages have been used on large volumes of oil, but such installations are rare. 69
Ratios of operating pressures between stage in multiple-stage separation can be approximated from the following equation:
R
P2
P3
=
n P1 √ --Ps
=
P1 --- = Ps R
Rn-1
=
P2 --- = Ps R
Rn-1
P1 P2 Pn Where , R = stage pressure ratio = = ----- = -------- = ……. ------P2 P3 Ps n P1 P2 P3 Ps
= number of inter-stages (number of stages – 1) = first-stage separator pressure, psia = second-stage separator pressure, psia = third-stage separator pressure, psia = storage-tank pressure, psia
70
Equilibrium flash calculations should be made for several assumed conditions of pressures and temperatures to determine the conditions that will yield the most stock-tank liquid. However, the above equation will give a practical approximation that can be used when no other information is available. Two-stage separation is normally considered to be obtained when one oil and gas separator is used in conjunction with a storage tank. Three-stage separation is obtained when two separators are used in series at different pressure, in conjunction with storage tank. Since gas may continue to separate or “weather” from oil in storage tanks, the storage tank is considered as a “stage” of separation. Slide - 64 shows schematically a four-stage separator installation. 71
Economic considerations of stage separation of Oil & Gas The extent of application of stage separation on economic consideration 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 to remove the condensable vapors from the gas and add them to the liquid increase its sales price (more API greater revenue). If, on the other hand, the liquid is sold on the basis of volume only, it may be desirable to leave the condensable vapors in the gas.
72
Other considerations of stage separation: * Physical and chemical characteristics of the well fluid * Flowing wellhead pressure and temperature * Operating pressures of available gasgathering systems * Conservation features of liquid-storage facilities * Facilities for transporting liquids. 73
The point of diminishing returns in stage separation is reached when the cost of additional stages of separation is not justified by increased economic gains. The optimum number of stages of separation can be determined by field testing and/or by equilibrium calculations based on laboratory tests (PVT) of the well fluid. Equilibrium flash calculations indicate accurately the gas and liquid from oil and gas separators if the composition of well fluid is known. 74
SAFETY FEATURES OF OIL & GAS SEPARATORS Oil & Gas separators are installed on offshore platforms / on land oil installations and invariably placed in close proximity to other equipments. In order to prevent damage to surrounding equipment and personnel in event of failure of the separator, its controls or accessories, following safety features are provided on O&G separators. * High- and low- liquid controls normally are floatoperated pilots that actuate a valve on the inlet to the separator, open a bypass around the separator, sound a warning alarm, or perform some other pertinent function to prevent damage that might result from high or low liquid levels in the separator. 75
76
High- and low- pressure controls are installed on separators to prevent excessively high or low pressures from interfering with normal operations. These high- and low- pressure controls can be mechanical, pneumatic, or electric and can sound a warning, actuate a shutin valve, open a bypass, or perform other pertinent functions to protect the separator and surrounding equipment. High and low temperature controls may be installed in or on the separator to shut in the unit, open a bypass or sound a warning should temperature in the separator become too high or too low. 77
Safety relief valves is a spring-loaded safety relief device which is usually furnished with and installed on all oil and gas separators. They normally are set at the design pressure of the vessel. Safety relief valves serve primarily as warning devices and inmost instances are too small to handle the full rated capacity of the separator. Full capacity safety valves can be fitted and are recommended when no safety head (rupture disk) is used on the separator. Safety head or rupture disk is a device containing a thin membrane that is designed to rupture when pressure in the vessel reaches a predetermined value. This is usually from 11/4 to 11/2 times the design pressure of the vessel. The safety head is usually selected so that it will not rupture until after the safety relief valve has opened and safety relief valve is incapable of preventing excessive pressure buildup in the separator. (Not preferred now)
78
79
SAFETY ANALYSIS OF PRESSURE VESSELS
80
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.) would make the vessel selected difficult to operate or maintain • Make certain that there is no design requirement (heating coils for paraffin or hydrate or 3-phasing for water removal etc.) that would make the shape selected expensive to use or difficult to operate 81
