214615832 Oil Gas Separators

17 Apr. 00

ADMA-OPCO On-site Training Course

Process / Production Module - 8

OIL & GAS SEPARATORS

Gap Elimination Program

D:/SO/wr/IHRDC-Modules/Module-08-O&G Sep.doc 61

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Process / Production

Module – 8

OIL & GAS SEPARATORS


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Table of Contents 1.

Separation Fundamentals -

Separation Vessels System Problems Factors Affecting Separation

2.

Separator Selection

3.

Separator Components

4.

Vessel Terminology

5.

Types of Separators

6.

Separator Internals

7.

Material of Construction

8.

Tag Number

9.

Separator Applications

10.

Separators Control and Safety Systems

11.

Separators Operational Procedures -

Start-up Shut-down Routine Operation Separator Isolation for Internal Inspection

12.

Troubleshooting

13.

ADMA-OPCO Gas-Oil Separators


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OBJECTIVES

Upon completion of this module, the developee will be able to: • Identify and explain the function of each major component of the separator. • Explain how separators work • Explain when different separators are used. • Describe how liquid levels and gas pressure are maintained in separators. • Identify the safety devices for separators.


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1.

SEPARATION FUNDAMENTALS

A)

Separation Vessels

Separation vessels may be divided into two classes • Scrubbers • Separators A Scrubber is any vessel designed for separation of liquid from gas that does not have sufficient capacity to handle surges of liquid. It is designed to handle relatively small quantities of liquid with no degree of surging. The scrubber is NOT used as a primary separation vessel. Scrubbers are recommended only for: 1. Secondary separation to remove carryover fluids from gas 2. Removal of dust and other impurities from gas 3. Miscellaneous separation where the gas-liquid ratio is extremely high. A separator is a mechanical device used for primary separation of liquid and gas, which is normally accomplished with the aid of centrifugal force. Either a tangential inlet or internal diverter is used to cause a spinning motion to the incoming fluid. A properly designed separator will also provide a means for releasing the entrained gases from the accumulated hydrocarbon liquids.


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The objective of ideal separator selection and design is to separate the hydrocarbon stream into liquid-free gas and gas-free-liquid. Ideally, the gas and liquid reach a state of equilibrium at the existing conditions of Pressure and Temperature within the vessel.

Figure –1 Separation Process

Two factors are necessary for separators to function: 1-The fluids to be separated must be insoluble in each other. 2-One fluid must be lighter than the other. Separators depend upon the effect of gravity to separate fluids. If they are soluble in each other, no separation is possible with gravity alone. For example, a mixture of distillate and crude oil will not separate in a vessel because they dissolve in each other. They must be segregated by the distillation process.


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Gravity Separation Since a separation depends upon gravity to separate the fluids, the ease with which two fluids can be separated depends upon the difference in the density or weight per unit volume of the fluids. In the process of separating gas and liquid, there are two separation stages: 1- Separate liquid mist from the gas phase. 2- Separate gas in the from of foam from the liquid phase. Droplets of liquid mist will settle out from gas, provided thtat: • The gas remains in the separator long enough for mist to drop out. • The velocity of the gas through the separator is slow enough that no turbulence occurs. Gas bubbles in the liquid will break out in most oil field applications in 30 to 60 seconds. Therefore, separators are designed where the liquid remains in the vessel for 30 to 60seconds. The length of time that the liquid remains in the vessel is called residence time or retention time.

B) Separation system problems The main problems encountered in oil and gas separation are: • • • •

Liquid slugging Dust Oil fogs Mist

Dust: causes erosion of compressor intake valves and plugging of small orifices in various controlling and process equipment.


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Oil fogs and mist: Create environmentally and process equipment problems because they contaminate lubricants, chemicals and desiccants. These are common problems in natural gas pipelines, compressor stations, conditioning equipment, and control systems.

C.

Factors Affecting Separation

The factors that affect the separation of liquid and gas phases in a separator are: • • • • •

Separator internals Fluid stream composition Operating pressure Operating temperature Residence time

Changes in any one of these factors on a given fluid stream will change the amount of gas and liquid leaving the separator. Effect of factors that cause separation Separation factor 1.Difference in weight of fluids 2. Residence time

Effect of factor Separation is easier when weight difference is greater. Separation is better with longer time

3. Coalescing surface area

Separation is better with larger area

4- Centrifugal action

Separation is better at higher velocity

5- Presence of solids

Makes separation more difficult

6- Operating pressure

More gas will remain in solution at higher pressure More volatile liquid components will be lost at higher temperature

7- Operating temperature


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2.

Separators Selection

Several factors should be considered when selecting a separator for a specific application. These factors are: Inlet Flowrate The size of the selected separator should match with the inlet rate of the fluid being separated. A margin in the separator capacity should be taken into account for future increases in the inlet rate.

Stream Characteristics In addition to the obvious quantities of liquid and gas to be separated, the following characteristics influence the vessel selection. • • • •

Proportion of gas and liquids composing the inlet stream. Difference between the viscosity of the gas and that of the liquid Particle size of liquid droplets in the gas phase The actual size of the separation section must meet both the retention time and settling velocity criteria. • Existence of impurities or special conditions such as H2S, CO2, pipe scale, foam, fogs, etc. • Instantaneous flow rates (slugging or heading). Retention Time • It is the time a single droplet theoretically remains in the vessel. • The average retention time for typical separation vessels is as follows: Two-phase Separators 35 API Oil and higher 20 API Oil 15 API Three-phase Separators 35 API Oil and higher 20 API Oil 15 API


Minutes 2.0 3.0 4.0 Minutes 5.0 10.0 15.0

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3.

SEPARATOR COMPONENTS

All types of separators have four main sections (Figure 2). These sections are: • • • •

Primary separation section. Secondary separation section. Liquid accumulation section. Mist extraction section.

Primary Separation Section This section removes the bulk of liquid in the inlet stream. Slugs and large liquid particles are removed first to minimize gas turbulence and re-entrain of liquid particles. To do this, the velocity and direction of flow are changed. Centrifugal force created by either inlet baffle or internal piping allows for changes of flow direction and reduction of stream velocity. Secondary Separation Section The separation principle in this section is gravity settling of liquid from gas after stream velocity has been reduced. The efficiency of this section depends on : • The gas and liquid properties. • Particle size. • Degree of gas turbulence. Some designs use straightening vanes to reduce turbulence. The vanes also act as droplet collectors.


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Liquid Accumulation Section Liquids and solids collect in this section. Because the section is away from stream turbulence, gravity causes dense solids such as sand and clay to settle on the separator bottom . These are removed periodically. Liquids continue to collect until the level reaches the designed dump level .The liquid level controller cause the liquid-level control valve to open and liquids flow out from the separator. Two factors determine the capacity of this section : 1. The volume of well stream surges. 2. The time liquid must remain in this section for efficient breakout of solution gas. Mist Extraction Section It removes the very small droplets of liquid in a final separation step before the gas leaves the vessel. The mist extractor has a several designs, for example, a series of vanes and woven -wire mesh pad. More recent designs use the woven wire mish pad

4.

VESSEL TERMINOLOGY:

The term "oil and gas separator", in oil field terminology, designates a pressure vessel used for the purpose of separating well fluids into gaseous and liquid components. A separating vessel may be referred to as in the following ways: 1. Oil and gas separator 2. Separator 3. Stage separator 4. Trap 5. Knockout (vessel) (drum) (trap) - Water knockout - Liquid knockout 6. Flash chamber (trap) (vessel) 7. Expansion vessel (separator) 8. Scrubber (gas scrubber) 9. Filter (gas filter). D:/SO/wr/IHRDC-Modules/Module-08-O&G Sep.doc 61

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The terms oil and gas separator, separator, stage separator, and trap all refer to a conventional oil and gas separator. These separating vessels are normally used near the wellhead, manifold, or tank battery to separate the fluids produced from oil and gas wells into oil and gas or liquid and gas. They must be capable of handling "slugs" or "heads" of well fluids. A knockout (vessel) (drum) (trap) may. be used to remove only water from the well fluid or all liquid oil plus water, from the gas. In the case of a water knockout the gas and liquid petroleum are discharged together and the water is separated and discharged from the bottom of the vessel. A liquid knockout is used to remove all liquid, oil plus water, from the gas. The water and liquid hydrocarbons are discharged together from the bottom of the vessel and the gas is discharged from the top.

5.

TYPES OF SEPARATORS

Separators are classified in two ways: 1. According to the shape of the vessel. 2. According to the number of the fluids to be separated.

Classification According to the Vessel Shape Separators are commonly manufactured in three basic shapes: a. Horizotal Separators b. Vertical Separators c. Spherical Separators

A. Horizontal Separators The horizontal separator (figures 3, 4 & 5) is designed for processing well stream with large volume of gas .The large liquid surface area provides efficient removal of gas from the liquid. This type of vessel has a large interface area between the liquid and the gas phases, thus, adding more separation capability when the gas capacity is a design criteria. The horizontal vessel is more economical in high-pressure separators due to increased wall thickness required with large diameters. However, the liquid level control replacement is more critical than that in vertical separators. D:/SO/wr/IHRDC-Modules/Module-08-O&G Sep.doc 61

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Figure 4 – Three-Phase Horizontal Separator


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B. Vertical Separators This type (Figures 5, 6 & 7) is capable of handling large slugs of liquid without carryover to the gas outlet and is best suited for well streams with high liquid content and low gas volume. The action of level control is not critical. Due to the greater vertical distance between the liquid level and the gas outlet, there is less tendency to re-vaporise the liquid into the gas phase. Vertical type is most often used for fluid streams having considerably more liquid than gas.

C. Spherical Separators Spherical separators (Figure 8) are compact vessels and provide good gas separation. However, they have very limited surge space and liquid settling section. When a well stream contains excess mud or sand or is subjected to surging foamy components, the spherical separator is not economical. The liquid level control is very critical. These Separators are not popular today because of their limitations.


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Typical Separators


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Figure 6 Two-Phase Vertical Separator D:/SO/wr/IHRDC-Modules/Module-08-O&G Sep.doc 61

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Figure 4 - Three

Figure 7 Vertical Separator


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Figure 8 Spherical Separator


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Classification According to the Number of Fluids to be Separated Normally, fluids to be separated are either two or three fluids. In case of two fluids such as gas and liquid, the separator to be used is a two-phase separator, which may be a horizontal or vertical type. If three fluids are to be separated such as gas, oil and water the vessel to be used is a three-phase separator. The number of phases refers to the number of streams that leave the vessel, and not the number of phases that are in the inlet stream. For example, well stream test separator frequently has gas, oil and water but only the liquid and gas are separated in the vessel. Consequently, a twophase separator is one in which the inlet stream is divided into two outlet fluids, and a three-phase separator is one which has three outlet fluids. Some well streams contain sand or other solid particles which are removed in a separator. Special internal devices are provided to collect and dispose of solid materials. They are not considered another phase in this type of vessel classification. A- Two-Phase Separators (Figures 3 & 6) The flow in horizontal or vertical separators is similar. The well stream enters the inlet side and strikes a baffle. Forward motion is stopped temporarily with the heavy liquids falling to the bottom of the vessel. Gas and liquid spray continue through straightening vanes, which cause liquid drops to form and drop into the accumulation section. As in figure 6, flow in a centrifugal separator is somewhat different than that in conventional types. The vessels are usually vertical and depend on centrifugal action to separate the fluids. The inlet stream is directed to flow around the wall of the vessel in swirling motion. The heavier liquid moves to the outside, and droplets collect on the wall and fall to the bottom. The lighter fluid collects in the middle part of the vessel above the outlet pipe. B- Three-Phase Separators This type handles gas plus two immiscible liquid phases. The two liquid phases might be oil and water, glycol and oil, etc. The potential application of three phase separators occurs where space is a major consideration.


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Figure 9 – Vertical Separator with Sand Removal facilities

Remova l


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6.

Separator Internals

Production equipment involving the separation of oil and gas usually have a wide variety of mechanical devices that should be present in all separators, regardless of the overall shape or configuration of the vessel. These mechanical devices improve the separator’s efficiency and simplify its operation. The most commonly used devices are: • • •

Inlet configuration Intermediate configuration Outlet configuration

A- Inlet Configuration In horizontal separators the inlet configuration can take many shapes as shown in the figures (10& 11). The most commonly used are: -

Structural channel iron Angle iron Flat plates Dished heads Schopentoeter

The latter three shapes have been considered the optimum configurations for certain applications. These shapes are used in gas – liquid separators in front of the inlet nozzle of the vessel, which serve two purposes: 1. To aid in the separation of entrained gas from the liquid. 2. To divert the fluid flow downstream. In vertical separators, there is a centrifugal inlet device (Figures 6 & 7), which causes the primary separation of the liquid and gas to take place. Here, the incoming stream is subject to a centrifugal force as much as 500 times the force of gravity. This action stops the horizontal motion of the liquid droplets together, where they will fall to the bottom in the settling section.


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Schoepentoeter The Schoepentoeter (vane-type) is a Shell-property inlet device and is commonly used for introducing gas/ liquid mixtures into a vessel or column It is used to absorb the initial momentum as the well fluid enters the separator. It tends to deflect the direction of flow causing gas to rise and free liquid to drop that the flow encounters a drop in velocity as well as reduction in pressure. Figure 11 shows schematically the typical outline of a Schoepentoter in a vertical vessel together with its design parameters (for simplicity not all the vanes are shown). The geometry of the Schoepentoter is largely standardised so that the choice of dimensions to be made by the designer is limited to the following: • The number of vanes per side nv. • The vane angle a, which is 8 degrees o less. • The length of the straight part of the vanes, Lv , which shall be 75, 100, 150 or 200 mm. The choice of Lv is also used to fix the vane spacing. • The radius of the vanes, Rv, which shall be 50 or 100 mm. With a Schoepentoeter, it is normal to specify a protruded nozzle, although this is not essential.


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Figure 10 Schematic Outline of the Schoepentoeter


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a B. D. d1. E Lv nv Rv t

= vane angle, angle made by straight part of vanes with centre line. = edge angle, angle made by edge of the row of vanes with centre line. = vessel inside diameter, mm. = inlet nozzle inner diameter, mm. = available space, mm. = length of straight part of vanes (normally 75, 100, 150 or 200 mm) = number of vanes per side. = vane radius, mm (normally 50 or 100 mm) = vane material thickness, mm (normally 3 mm, but typically 5 mm for heavy duty, e.g slugs) W1/0 = width of vane entrance opening, mm.


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B- Intermediate Configuration The most commonly used configurations of these intermediate devices are: • • • •

Coalescing plates Straightening vanes Weir Horizontal baffles

These are commonly used in gravity separation sections and are as follows: - Coalescing plates (Figure 4) Several configurations are available. They are used in gas-liquid vessels to remove liquid from the gas and are not used where hydrate or paraffins are present. - Straightening vanes (Figure 3a) These are used to separate liquid mist from gas where hydrates or paraffins are present. They are used when hydrates or paraffins prevent the use of pads. - Weir (Figures 5) As illustrated in figures, it is a dam-like structure, which is controlling the liquid level and keeps it at a given level. Maybe one or two weirs are used in one separator, where one maintains the oil level and the other maintains the water level. - Horizontal Baffles (Figure 4) These are used in large gas liquid separators to prevent waves in the liquid phase.

C- Outlet Configuration These mechanical outlet devices are sometimes used in horizontal and vertical separators, and the most commonly used are the following. - Mist pad or extractor – (Figurers 3, 6 & 12) Most frequently used in gas - liquid separators and normally located near the gas outlet to coalesce small particles (mist) of liquid that will not settle out by gravity. It breaks oil-water emulsion to help in segregating the two liquids. It is not used where hydrates or paraffins may be present. The stainless steel woven wire mesh misteliminator of thickness 10 – 20 cm (4-8 inchs) is considered to be the most efficient type.


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It is held in place by a stud grid which prevents it from being swept out or torn by a sudden surge of gas, and has been proven to remove up to 99.5% or more of the entrained liquids from the gas stream.


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- Wire Mesh Demister (Figures 12 & 13) This type offers the greatest area for the collection of liquid droplets per unit volume as compared to vane type. - Vane Type – (Figures 3 & 13) It consists of a labyrinth formed with parallel metal sheets with suitable liquid collection pockets. The gas passing between plates is agitated and has to change direction a number of times. Vane type mist eliminators have their applications in areas where there are entrained solid materials in the gas phase.


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- Vortex Breakers The liquid outlet should be equipped with anti-vortex devices to prevent a vortex from forming, and gas from going out with the liquid. Several types are shown in the figure.

Figure 14 Outlet Vortex Breaker

7.

Material of Construction

Most separators operate under pressure. They are usually constructed of steel which is built in accordance with rigid pressure vessel specifications. The heads and shell are usually made of steel, and all seams are welded. If severe corrosion is anticipated, the separator may be internally lined with corrosion resistant material such as monel or stainless steel. If salt water is the corrosive agent, protection can be provided by coating with special paint or tar. Most internals are also made of steel and welded to the wall of the vessel. If man-ways are provided, the internals may be bolted in place so that they can be removed for cleaning or repairing.


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8.

Tag Number (name Plate)

Tag numbers are necessary to identify instruments, vessels and equipment in the plant. In addition, they help in identifying the functions of plant vessels and equipment. For example a centrifugal pump can have various uses, but the tag number will help in identifying its function. In process plants, tag numbers are of particular importance to operation and maintenance personnel as they help them understand the functions associated with each installation. Tag numbering system is designed to prevent confusion between interments/vessels or equipment of the same function when they are located in different process units in an installation.


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9.

SEPARATOR APPLICATIONS

Separators are a vital part of production operations. Their most common application in the oil patch is to segregate gas, oil, and water. Each of the three fluids must have virtually 100% removal of the other fluids in order to have the highest commercial value. Liquid must be removed from a gas stream to prevent it from accumulating in low parts of a pipeline and restricting the flow of gas. If the gas requires processing in a dehydration or sweetening plant, liquids must be removed to prevent serious operational problems in the processing plant. Crude oil must be free of gas so that storage tanks will not be subjected to hazards resulting from escaping gas. The water content of crude oil must be low in order to prevent a reduction in its value. For environmental reasons as well as energy conservation requirements, it is usually necessary to remove oil from water that is discharged in any process operation. The following table shows the most common applications of the different types of separators.


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Table 3.1 Common applications of horizontal and vertical Separators TYPE

APPLICATION

Horizontal

1. High gas-oil ratio streams. 2. Oil-water segregation where long residence time is required.

Vertical

1. Low gas-oil ratio streams. 2. In packaged process plants (limited space). 3. Where a high level of liquid must be held to prevent a pump from vapor locking, or maintain a liquid seal.

The designation of high or low gas-oil ratio is rather arbitrary. The following are specific instances in which high or low GOR's usually occur: LOW GAS-OIL RATIO • • •

Oil well streams Flash tanks in dehydration and sweetening plants Fractionator reflux accumulators

HIGH GAS-OIL RATIO • • • • •

Oil well streams Gas well streams Gas pipeline scrubbers Compressor suction scrubbers Fuel gas scrubbers

The terms Flash Tank, Accumulator and Scrubber are commonly used for specific applications of separators. The vessels are gas-liquid separators.


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10. SEPARATORS CONTROL AND SAFETY SYSTEMS A. Control Separators have two major control points: 1. Pressure control. 2. Level control. Pressure Control (Figure 15) Control of pressure and level are basic for good separator operation. The pressure of the separator must be rather constant, independent of the operation of adjacent equipment. Usually, this means a backpressure valve on the gas outlet, any off-set due to flow rate changes normally causes no problem. However, the vessel design pressure and high pressure alarm or shut down controls must be consistent with the range of pressure expected for the proportional setting and off-set anticipation. The pressure in a separator should not exceed the preset operating pressure of the vessel. Therefore, pressure is regulated with a pressure control valve, which regulates the flow of gas leaving the vessel. Level Control (Figure 15) Two-Phase Separators Level Control In horizontal separators the liquid level in the separator has a significant effect on the performance of the vessel. The level of liquid in the separator needs to be properly controlled so that it does not affect the space occupied by gas in the vessel. If the liquid level is high, it will reduce the vapour disengaging space and can result in some liquid carrying over in the outlet gas stream.


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Figure 15 Separator Pressure and Level Controls

In a vertical separator the liquid level will not have much effect on the quality of the gas out of the vessel because the vapour space is usually several meters (feet) high, and a few centimetres (inches) will have a little effect. Three-phase Separators Level Control A three-phase separator is one in which the outlet streams are gas and two liquids. In almost every 3-phase separator, one of the liquids is oil, and the other one is usually water, but it may be glycol, brine, amine or any other liquid that is not soluble in oil. Level control in three-phase separators for oil and water individually has a little importance because control of the water level will affect the level of both water & oil.


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B.

Safety Devices

One of the most serious concerns in any process plant is the possibility of explosions or rupture of pressurized equipment. These dangerous conditions occur when operating pressure exceeds the design limits of the equipment. In order to prevent this occurrence, various types of safety devices are installed to relief the internal pressure when it exceeds the operating limit. • Pressure Relief Valve: This opens automatically when the process pressure exceeds the high limit (design pressure), and discharges the excess pressure from the system. This valve is installed on the outlet of the vessel. • Rupture Disc: It is used to protect process vessels from overpressure. It bursts, or ruptures when the process pressure exceeds a pre-determined limit. • Shutdown Valve: Most process are provided with automatic controls that shutdown in the event of a dangerous process condition. Shutdown valves are normally located in the inlet manifold upstream of the vessel. • Blowdown Valve: Blowdown valves are used for plant depressuring during emergency or plant maintenance shutdown.

• Pressure Switches: The vessel is protected against over pressure by a pressure switch high (PSH) which indicates a pressure alarm high and a pressure switch high high (PSHH) which initiates process shutdown (PSD) system.


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11. SEPARATORS OPERATIONAL PROCEDURES A.

Start up of a Separator 1. Ensure that the drain / vent valves are closed and the spades /blinds have taken off where not required 2. Ensure that the vessel is hydro tested and purged.(Nitrogen Purge) 3. Check and ensure that the instruments are on line/ service. (calibrate them if required) 4. Ensure that the safety systems are on line. 5. Check and set the set points on the controllers as required 6. Ensure that the vessel is properly lined up. 7. Introduce the well fluids at a controlled rate and monitor the increase in pressure and level in the vessel. 8. Adjust the controller set points as required (Gas/ oil/water). 9. When the pressure and level reach the desired set values, normalise the alarms and shut down switches on the panel. 10. Install the orifice to get proper gas flow readings. 11. Reset the oil counter.

B.

To-Shut down a Separator 1. Raise the orifice in the chamber. 2. Bypass the alarm /shut down switches as required. 3. Divert the flow and isolate the separator. 4. Ensure that the level and pressure are in safe positions.

5. Drain/vent the vessel as required. D:/SO/wr/IHRDC-Modules/Module-08-O&G Sep.doc 61

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C.

Routine Checks For the Operator 1. Check the separator pressure. 2.Check the separator temperature. 3.Check the gas flow 4.Check the level in the sight glass. 5 Verify the level of the transmitter and sight glass. 6. Check that the instruments are in service. 7. Check the PD of the filters. 8. Check the oil /water flow meters 9. Ensure that the safety systems are in service. 10. Check for any abnormal noise or leaks.

D.

To Isolate a Separator for internal Inspection 1. Carry out background NORM /L. S. A checks. 2. Raise the orifice to the upper chamber. 3. Bypass the alarm/shutdown switches as required. 4. Divert the flow. 5. Reduce the level/pressure in a safe manner. 6. Drain /vent the vessel as required. 7. Adhere to safety policies. 8. Check the validity of the permit, and the permit conditions. 9. Isolate the vessel with double block isolation. 10. Spade the vessel as required. 11. Open the monitor (ensure that the fire extinguisher and the fire water pump are stand by)


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12. TROUBLESHOOTING This is a topic to state an example, where an operator gains confidence through experience only. An operator on these daily routines notes down the log readings. He observes that the level in the sight glass is normal. But the separator has tripped on high level. It is the job of the operator to check whether it is an actual alarm or a faulty one. He should follow the following procedure: 1. Stop the audible alarm, bypass the switch and energise the panel. 2. Check the transmitter and the sight glass, to determine the actual level. 3. If the level is normal, isolate and drain the L. S.H.H if it still remains unhealthy then call in the instrument technician to check it out. 4. On isolating and draining, if it comes back to normal for some reasons the switch could have been sticking. Have it cleaned and serviced by the instrument technician. 5. There could also be an instance when the switch on the separator is healthy but the separator has tripped on LSHH on the panel. This indicates that there is an air leak, and the tube has burst, venting off the air from the shut down loop of the separator. The above situation is just an example for the operator to know how to troubleshoot/analyse a particular problem.


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A-

Troubleshooting Procedure for Liquid Carryover in Outlet Gas Stream

Cause of Carry Over 1. Excessive inlet gas flow rate

Troubleshooting Procedure Check gas flow rate and cut back to design rate

2. High liquid level which cuts down vapor disengagging

Check liquid level. Blow down gauge glass. Lower level to design point

space 3. Coalescing plates or mist pad

a. Check temperature and pressure to

or centrifugal device is plugged with dirt or hydrates

determine if hydrates can form . b. Measure pressure drop across device. It should be less than 0.1 bars [2 psi]. If drop across mist pad is 0, pad may have torn or come loose from its mounting. Pressure drop measurement should be made at the design gas rate. High-pressure drop indicates plugging. Internally inspect if necessary.

4. Excessive wave action in

Check or install horizontal baffles.

liquid 5. Operating pressure is blow design pressure

Check pressure and raise to design pressure or lower gas rate in proportion to reduction in pressure

6. Liquid API gravity is higher than its design value

Check liquid gravity. If it is above its design value, gas rate will have to be cut in proportion to difference in gravity.


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B.

Troubleshooting Procedure for Inability to Hold a Constant Liquid Level

Cause of Level Change 1. Float is totally covered with liquid

2. Liquid level is below float

Note: Level controller will not function if the liquid level is 0. Allow level to rise above the float until float is covered. Float must be partially immersed in order for the controller to work. 3. Liquid flow rate has changed.


Troubleshooting Procedure a. Blow down gauge glass to get accurate level reading. b. If float cage is external, blow it down to ensure pipes between cage and vessel are not plugged. c. When gauge glass and float cage are clean, check if float is covered with liquid. d. Manually drain enough liquid from vessel so that ½ of float is immersed. a. Perform steps a and b above. b. If level is below float, close valve on liquid line. c. Put level controller in liquid in service.

a. If level controller does not have reset, the level control point on the controller will have to be changed each time the liquid rate changes b. If controller has reset, it can be adjusted to take care of changes in liquid flow rate.

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B.

Troubleshooting Procedure for Inability to Hold Constant Liquid Level (Cont'd)

Cause of Level Change

Troubleshooting Procedure

4. Liquid enters vessel in slugs. Level a. Lower level set point on controller. controller does not react fast enough b. Lower proportional band setting. to drain liquid. c. In some cases it may be helpful to install a valve positioned on the level control valve in order for it to open rapidly. 5. Level control valve is not operating a. Check valve action to see that it is not properly. closing when it is supposed to open. b. Stroke-valve to fully open and closed positions to see that the spring tension is not too tight or too loose, and that nothing is under the valve seat to prevent it form closing. c. Check liquid flow rate with valve fully open to see that there is no restriction in the line. 6. Wave action is causing internal Install float shield. float to move. 7. Level controller shows no response a. Manually twist torque tube or float arm to see that controller shows to change in level. response. If there is no response, repair controller. If controller shows response, float has apparently dropped off, or liquid level is above or below float. b. Check liquid level as described in items 1 & 2. c. Manually open and close drain valve so that the liquid level travels the full length of the float. If the controller shows no response, the float had fallen off.


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B.

Troubleshooting Procedure for Inability to Hold Constant Liquid Level (Cont'd)

Cause of Level Change 8. Float in oil-water interface is totally immersed in emulsion.

Troubleshooting Procedure a. Check for emulsion in vessel by draining a line connected to the vessel near the float. b. Drain emulsion from vessel if it is present.

9. Gravity of oil has changed so that float will not respond to change in level.

a. Check gravity of liquid. b. If it is different from its design value, consult level controller supplier to get a new float.


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C.

Troubleshooting Procedure When One Liquid Contains an Excessive Amount of the Other Liquid.

Cause of Excessive Amount of Liquid

Troubleshooting Procedure

1. The flow rate of one or both liquids is Check flow rates and cut back to design high. 2. The temperature of the liquids is below its design value. 3. Filters or coalescing material is plugged.

rates. Check the temperature and raise it to the design temperature a. Check pressure drop across coalescing device. b. Clean or replace coalescing material or filter elements.

4. Interface level is above or below float a. Blow down gauge glass and cage to so that level controller will not function.

get accurate level indication. b. Open or close valve on liquid lines as required to bring interface level to centre of float.

5. Improper interface level

a. If oil contains water, interface level is too high. Level must be lowered. b. If water contains oil, interface level is too low. Level must be raised.


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ADMA-OPCO GAS - OIL SEPARAORS


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4.

SYSTEM DESCRIPTION 4.1

HP SEPARATORS There are seven HP separators presently in use for processing the partially stabilised crude oil at the Umm Shaif Plant (USP) facilities. An arrangement of pipework and manifolds fitted with diverter valves splits into individual 8 inch crude inlet lines for the following HP separators: • • • • • •

No 8 No 10 No 12 No 14 No 16 No 18

This is to ensure that an equal volume flowrate of crude is directed to each HP separator. A separate 16 inch HP crude header feeds HP separator No 20, which was commissioned at a later date. The following text describes the facilities provided for HP Separator No 8. The identical facilities provided for other HP Separators are included in Table 1 on the next page. As shown in Figure 3.2, the inlet line is fitted with a choke valve, pressure control valve and shutdown valve. The choke valve is manually operated and controlled by the Production Operators. The second valve is the pressure control valve PV-040A which operates under the management of the MOL pressure controller PICR-040 to maintain the oil reception pressure at 500 psig. The third valve on the inlet line is the shutdown valve SDV-100 which is controlled by the ESD system. As crude oil enters the HP separator through a tangential pipe into a cyclone chanmber, it is diverted downwards in a spray. Inside the separator, the crude oil is subjected to a reduction in pressure and velocity. The reduction in pressure to 250 psig in conjunction with the designed retention time, causes the three phase separation of oil, gas and produced water to take place inside the vessel. On the upstream side of the weir, produced water is discharged under interface level control (LV-108) to the SWDP via the degassing drum for further treatment. D:/SO/wr/IHRDC-Modules/Module-08-O&G Sep.doc 61

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Evolved gas inside the vessel passes through a straightening section followed by a series of demister pads to the gas chamber through a tangential pipe. The separator off-gas flows to the HP scrubber. A flow orifice FE-116 is installed in the gas outlet line to measure the flowrate of gas being discharged from the separator. A motorised valve HV-117 is provided for vessel isolation. The operating pressure of all the HP separators is controlled at 250 psig by PCV-460A/F HP gas pressure control system. A demister pad is located at the gas separator outlet to catch any entrained liquid droplets in the gas stream which coalesce and collect in the gas chamber boot. Liquids from the gas chamber boot are dumped under level control to the oil outlet line from the HP separator. The oil level on the downstream side of the weir is controlled by Level Control Valve LV-104 which maintains an oil level in the separator to prevent gas blow-by. Oil from the vessel and liquids from the gas chamber boot are directed through an intermediate header to the LP separators. Figure 3.3 shows the internal parts of an HP Separator. The equipment tag numbers for all HP Separators are tabulated below. Table 1 HP Separator Tag Numbers

HP Separator

Inlet SDV

ProducedW ater LCV

Gas Outlet MOV

Separator Boot LCV

Recovered Oil LCV

No 8

SDV-100

LV-108

HV-117

LV-111

LV-104

No 10

SDV-140

LV-148

HV-157

*

LV-144

No 12

SDV-180

LV-188

HV-197

LV-191

LV-184

No 14

SDV-220

LV-228

HV-237

LV-231

LV-224

No 16

SDV-260

LV-268

HV-277

LV-271

LV-264

No 18

SDV-300

LV-308

HV-317

LV-311

LV-304

No 20

SDV-340

LV-348

HV-357

LV-351

LV-344

* HP Separator No 10 is not fitted with a gas boot.


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4.2

LP SEPARATORS There are seven LP separators presently in use for processing the crude oil recovered from the HP separators. The 12 inch intermediate header from the HP separator splits into individual 10 inch crude inlet lines for the following LP separators: • • • • • • •

No 9 No 11 No 13 No 15 No 17 No 19 No 21

This is to ensure that an equal volume flowrate of crude is directed to each LP separator. The following text describes the facilities provided for LP separator No 9. The identical facilities provided for other LP separators are included in Table 2 on the next page. As shown in Figure 3.2, the inlet line is fitted with a manual isolation valve, and a shutdown valve. The manual isolation valve is always in the open position unless the LP separator is isolated for maintenance. The Shutdown Valve SDV-120 is the second valve on the inlet line and is controlled by the ESD system. The LP separator operates in a similar manner to the HP separator with the exception of the gas chamber boot. The LP separator is not provided with a gas boot as the gas evolved in the vessel has relatively less entrained liquids.The reduction in pressure to 40 psig in conjunction with the designed retention time causes three phase separation to occur. On the upstream side of the weir, produced water separated is discharged under Interface level control to the SWDP via the degssing drum for further treatment. Released gas is discharged to the LP gas scrubber, via Flow Orifice FE-136 and a downstream motorised Isolation Valve HV-137. The operating pressure of all the LP separators is controlled at 40 psig by the LP gas pressure control system.


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The oil level on the downstream side of the weir is controlled by Level Control Valve LV-124 which maintains an oil level in the separator to prevent gas blow-by. Oil from the vessel is discharged through a 30 inch LP header to the US Horton spheroids, (see Module 4). The equipment tag numbers for all LP Separators are tabulated below. Table 2 LP Separator Tag Numbers

LP Separator

Inlet SDV

ProducedW ater LCV

Gas Outlet MOV

Separator Boot LCV

Recovered Oil LCV

No 9

SDV-120

LV-128

HV-137

-

LV-124

No 11

SDV-160

LV-168

HV-177

-

LV-164

No 13

SDV-200

LV-208

HV-217

-

LV-204

No 15

SDV-240

LV-248

HV-257

-

LV-244

No 17

SDV-280

LV-288

HV-297

-

LV-284

No 19

SDV-320

LV-328

HV-337

-

LV-324

No 21

SDV-360

LV-368

HV-377

-

LV-364


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5.

CONTROL INFORMATION 5.1

SYSTEM CONTROL Crude oil feed to the HP separators is automatically controlled by the pressure control valves or PVs for the oil reception facilities. These PVs direct the crude oil through the inlet lines for the individual HP separators. If necessary, the manual choke valves located upstream of the PVs may be cut back by the Production Operators to restrict or stop the flowrate of crude to the HP separators. The operating levels in the HP and LP separators are automatically controlled by level control valves or LCVs. Although the level control valves may be adjusted locally, the set-points for the level controllers are normally adjusted from the Distributed Control System (DCS). The pressure of the HP and LP separators are automatically controlled by PCVs-460A/F (HP) and PCVs-480A/E (LP).


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5.2

INSTRUMENTATION HP Separators The instrumentation provided for all seven HP separators is identical. The major instrumentation associated with HP Separator No 8 is listed in the table below. The corresponding instrumentation associated with the other HP separators can be identified from the relevant P&IDs. TAG No

SERVICE

SETPOINT/ACTION

HP Separator No 8 LAHH-112

High High Oil Level Trip

- 95% Initiates ESD-3.3 shutdown

LALL-112

Low Low Oil Level Trip


LAL/H-104

Oil Level Low/High Level Alarm

Low - 20% High - 60%

LAL/H-111

Boot Level Low/High Level Alarm

Low - 10% High - 60%

LALL-109

Low Low Produced Water Level Trip


LAL/H-108

Produced Water Level Low/High Level Alarm

Low - 20% High - 80%

PAHH-114

High High Pressure Trip

- 275 psig Initiates ESD-3.3 shutdown

High Pressure Alarm

- 260 psig

PAH-116


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LP Separators The instrumentation provided for all seven LP separators is identical. The major instrumentation associated with the LP Separator No 9 is listed in the table below. The corresponding instrumentation associated with the other LP separators can be identified from the relevant P&IDs. TAG No

SERVICE

SETPOINT/ACTION

LP Separator No 9 LAHH-132

High High Oil Level Trip


LALL-132

Low Low Oil Level Trip


LAL/H-124

Oil Level Low/High Level Alarm

Low - 20% High - 60%

LALL-129

Low Low Produced Water Level Trip


LAL/H-128

Produced Water Level Low/High Level Alarm

Low - 20% High - 80%

PAHH-134

High High Pressure Trip

- 75 psig Initiates ESD-3.4 shutdown

High Pressure Alarm

- 60 psig

PAH-136


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6.

SAFETY 6.1

OPERATIONS

6.1.1 Start-up of the HP and LP Separators Once the HP and LP separators have been nitrogen purged, the separators must be pressurised with hydrocarbon gas from the ADGAS HP and LP systems before crude oil can be re-introduced to the vessels. Once the HP separator is pressurised to the normal operating pressure of 250 psig, the shutdown inputs are temporarily bypassed to allow the inlet shutdown valve for the vessel to be reset to the open position. The level controllers are reset to “Local Control” before crude is introduced to the HP separator. Once the choke is opened to introduce crude to the HP separator and operating conditions have stabilised in the vessel, the controllers can be reset to “Auto Control” with normal setpoints. The shutdown inputs are finally reinstated to provide vessel protection. The LP separator is started up in a similar manner. 6.1.2 Normal Operations The HP and LP separators normally operate with all level controllers set in automatic mode and controlled from the DCS. The operating pressure of the HP and LP separators is controlled by the HP and LP pressure control systems. It may be necessary to shutdown one or more of the HP or LP separators for maintenance or as a routine operation. To shutdown one of the vessels, the choke valve or manual isolation valve on the inlet line must be closed to stop the crude flowing into the vessel. Once the choke or manual isolation valve is closed the operating levels in the other separators must be checked. This is to ensure that the separators now in service can process the extra crude. The level controllers for the vessel are now switched to “Local Control” and the operating levels in the vessel reduced to a minimum. To avoid gas blow-by the operating levels in the vessel must not be reduced below the low low level trip points.


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Once the operating levels in the vessel are just above the trip points, the shutdown valve on the inlet line must be closed from the local field panel to isolate the vessel. The vessel can now be positively isolated for draining and depressurisation, if required. 6.2

ISOLATION VALVES The HP separators can be isolated manually or by ESD by the following shutdown valves located in the respective separator inlet line: • • • • • • •

SDV-100 (HP separator No 8) SDV-140 (HP separator No 10) SDV-180 (HP separator No 12) SDV-220 (HP separator No 14) SDV-260 (HP separator No 16) SDV-300 (HP separator No 18) SDV-340 (HP separator No 20)

The LP separators can be isolated manually or by ESD through the following shutdown valves located in the respective separator inlet line: • • • • • • •

SDV-120 (LP separator No 9) SDV-160 (LP separator No 11) SDV-200 (LP separator No 13) SDV-240 (LP separator No 15) SDV-280 (LP separator No 17) SDV-320 (LP separator No 19) SDV-360 (LP separator No 21)

There are no blowdown valves for the HP and LP separators. 6.3

TRIP LOGIC The trip logic for the HP and LP separators is shown in Figure 3.3.


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7.

ASSOCIATED SYSTEMS 7.1

STEAM Steam is available at the inlet lines to the HP and LP separators. This utility is used to remove heavy crude deposits from the internals of the separators and gas-freeing prior to man entry.

7.2

NITROGEN Nitrogen is available at each of the HP and LP separators to be used in purging operations. Prior to start-up the separators are purged to atmosphere until the oxygen content in the vessel is less than 2%. The purging process must be successfully completed to inert the vessels prior to the introduction of any hydrocarbons.

7.3

CORROSION INHIBITOR Corrosion Inhibitor from the Chemical Injection Package is injected to the 36 inch MOL upstream of the sphere receiver. This chemical protects the internal surfaces of the pipework from any corrosive effects of the wellfluids.


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7 D:/SO/wr/IHRDC-Modules/Module-08-O&G Sep.doc 61

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214615832 Oil Gas Separators

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