214615832 oil gas separators

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D:/SO/wr/IHRDC-Modules/Module-08-O&G Sep.doc Page 1 of61

17 Apr. 00

ADMA-OPCO

On-site Training Course

Process / Production

Module - 8

OIL & GAS SEPARATORS

Gap Elimination Program


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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.

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.

Figure 1 Separation 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 perunit 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 turbulenceoccurs. 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 Effect of factor

1.Difference in weight of fluids

2. Residence time

3. Coalescing surface area

4- Centrifugal action

5- Presence of solids

6- Operating pressure

7- Operating temperature

Separation is easier when weightdifference is greater.

Separation is better with longer time

Separation is better with larger area

Separation is better at higher velocity

Makes separation more difficult

More gas will remain in solution athigher pressure

More volatile liquid components will

be lost at higher 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 followingcharacteristics 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 timeand 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 Minutes

35 API Oil and higher 2.0

20 API Oil 3.015 API 4.0

Three-phase Separators Minutes

35 API Oil and higher 5.0

20 API Oil 10.0

15 API 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 separatorbottom . 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. Trap5. 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).


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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 streamwith 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.


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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


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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 maybe 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 two-

phase 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 aseparator. 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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Remova

Figure 9 Vertical Separatorwith Sand Removal facilities


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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 improvethe separators 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 actionstops 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, 150or 200 mm. The choice of Lvis 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 = vane angle, angle made by straight part of vanes with centre line.

B. = edge angle, angle made by edge of the row of vanes with centre line.

D. = vessel inside diameter, mm.

d1. = inlet nozzle inner diameter, mm.

E = available space, mm.

Lv = length of straight part of vanes (normally 75, 100, 150 or 200 mm)

nv = number of vanes per side.Rv = vane radius, mm (normally 50 or 100 mm)

t = 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 wherehydrates or paraffins may be present. The stainless steel woven wire mesh mist-

eliminator 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 BreakersThe 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 tagnumber 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 commercialvalue.

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 toprevent 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

Vertical

1. High gas-oil ratio streams.

2. Oil-water segregation where long residence time

is required.

1. Low gas-oil ratio streams.

2. In packaged process plants (limited space).

3. Where a high level of liquid must be held toprevent 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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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.

Figure 15 Separator Pressure and Level Controls


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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 pressureexceeds 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. Itbursts, or ruptures when the process pressure exceeds a pre-determined

limit.

Shutdown Valve: Most process are provided with automatic controls thatshutdown 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 duringemergency or plant maintenance shutdown.

Pressure Switches: The vessel is protected against over pressure by apressure 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 ifrequired)

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 inpressure 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 thealarms 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.


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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 PDof 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 actuallevel.

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 ishealthy 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 Troubleshooting Procedure

1.Excessive inlet gas flow rate Check gas flow rate and cut back to design

rate

2.High liquid level which cuts

down vapor disengagging

space

Check liquid level. Blow down gauge glass.

Lower level to design point

3.Coalescing plates or mist pador centrifugal device is

plugged with dirt or hydrates

a. Check temperature and pressure todetermine 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

liquid

Check or install horizontal baffles.

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 Troubleshooting Procedure

1. Float is totally covered with liquid a. Blow down gauge glass to getaccurate level reading.

b. If float cage is external, blow itdown to ensure pipes between cage

and vessel are not plugged.

c. When gauge glass and float cage areclean, check if float is covered with

liquid.

d. Manually drain enough liquid fromvessel so that of float is

immersed.

2.Liquid level is below float a. Perform steps a and b above.b. If level is below float, close valve

on liquid line.

c. Put level controller in liquid inservice.

Note:Level controller will not function

if the liquid level is 0. Allow level to

rise above the float until float iscovered. Float must be partially

immersed in order for the controller to

work.

3. Liquid flow rate has changed. a. If level controller does not havereset, 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 inliquid flow rate.


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B. Troubleshooting Procedure for Inability to Hold Constant Liquid Level

(Cont'd)

Cause of Level Change Troubleshooting Procedure4.Liquid enters vessel in slugs. Level

controller does not react fast enough

to drain liquid.

a. Lower level set point on controller.b. Lower proportional band setting.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

properly.

a. Check valve action to see that it is notclosing when it is supposed to open.

b. Stroke-valve to fully open and closedpositions 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 valvefully open to see that there is no

restriction in the line.

6.Wave action is causing internal

float to move.

Install float shield.

7.Level controller shows no response

to change in level.

a. Manually twist torque tube or floatarm to see that controller shows

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 initems 1 & 2.

c. Manually open and close drain valveso 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 Troubleshooting Procedure

8.Float in oil-water interface is totally

immersed in emulsion.

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

high.

Check flow rates and cut back to design

rates.

2. The temperature of the liquids is

below its design value.

Check the temperature and raise it to the

design temperature

3. Filters or coalescing material is

plugged.

a. Check pressure drop across

coalescing device.

b. Clean or replace coalescing material

or filter elements.

4. Interface level is above or below float

so that level controller will not

function.

a. Blow down gauge glass and cage to

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 splitsinto 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 eachHP separator. A separate 16 inch HP crude header feeds HP separator No20, 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 Table1 on the next page.

As shown in Figure 3.2, the inlet line is fitted with a choke valve, pressurecontrol valve and shutdown valve. The choke valve is manually operated andcontrolled by the Production Operators.

The second valve is the pressure control valve PV-040A which operatesunder the management of the MOL pressure controller PICR-040 to maintainthe oil reception pressure at 500 psig.

The third valve on the inlet line is the shutdown valve SDV-100 which iscontrolled by the ESD system.

As crude oil enters the HP separator through a tangential pipe into a cyclonechanmber, it is diverted downwards in a spray. Inside the separator, the

crude oil is subjected to a reduction in pressure and velocity. The reduction inpressure to 250 psig in conjunction with the designed retention time, causesthe three phase separation of oil, gas and produced water to take placeinside the vessel.

On the upstream side of the weir, produced water is discharged underinterface level control (LV-108) to the SWDP via the degassing drum forfurther treatment.


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Evolved gas inside the vessel passes through a straightening sectionfollowed by a series of demister pads to the gas chamber through atangential pipe. The separator off-gas flows to the HP scrubber. A flow orificeFE-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 forvessel isolation.

The operating pressure of all the HP separators is controlled at 250 psig byPCV-460A/F HP gas pressure control system.

A demister pad is located at the gas separator outlet to catch any entrainedliquid droplets in the gas stream which coalesce and collect in the gaschamber boot. Liquids from the gas chamber boot are dumped under levelcontrol to the oil outlet line from the HP separator.

The oil level on the downstream side of the weir is controlled by LevelControl Valve LV-104 which maintains an oil level in the separator to preventgas blow-by. Oil from the vessel and liquids from the gas chamber boot aredirected 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

HPSeparator

InletSDV

ProducedWater LCV

Gas OutletMOV

SeparatorBoot LCV

RecoveredOil 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 oilrecovered from the HP separators.

The 12 inch intermediate header from the HP separator splits into individual10 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 eachLP separator.

The following text describes the facilities provided for LP separator No 9. Theidentical facilities provided for other LP separators are included in Table 2 onthe 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 openposition unless the LP separator is isolated for maintenance. The ShutdownValve SDV-120 is the second valve on the inlet line and is controlled by theESD system.

The LP separator operates in a similar manner to the HP separator with theexception of the gas chamber boot. The LP separator is not provided with agas boot as the gas evolved in the vessel has relatively less entrainedliquids.The reduction in pressure to 40 psig in conjunction with the designedretention time causes three phase separation to occur.

On the upstream side of the weir, produced water separated is dischargedunder Interface level control to the SWDP via the degssing drum for furthertreatment.

Released gas is discharged to the LP gas scrubber, via Flow Orifice FE-136and a downstream motorised Isolation Valve HV-137.

The operating pressure of all the LP separators is controlled at 40 psig by theLP gas pressure control system.


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The oil level on the downstream side of the weir is controlled by LevelControl Valve LV-124 which maintains an oil level in the separator to preventgas blow-by. Oil from the vessel is discharged through a 30 inch LP headerto 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 PVsdirect the crude oil through the inlet lines for the individual HP separators.

If necessary, the manual choke valves located upstream of the PVs may becut back by the Production Operators to restrict or stop the flowrate of crudeto the HP separators.

The operating levels in the HP and LP separators are automaticallycontrolled by level control valves or LCVs. Although the level control valvesmay be adjusted locally, the set-points for the level controllers are normallyadjusted from the Distributed Control System (DCS).

The pressure of the HP and LP separators are automatically controlled byPCVs-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 thetable below. The corresponding instrumentation associated with the other HPseparators 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 - 5%


LAL/H-104 Oil Level Low/High Level Alarm Low - 20%

High - 60%

LAL/H-111 Boot Level Low/High LevelAlarm

Low - 10%High - 60%

LALL-109 Low Low Produced Water Level

Trip

- 25%


LAL/H-108 Produced Water Level Low/HighLevel Alarm

Low - 20%High - 80%

PAHH-114 High High Pressure Trip - 275 psigInitiates ESD-3.3 shutdown

PAH-116 High Pressure Alarm - 260 psig


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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 otherLP 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 - 95%


LALL-132 Low Low Oil Level Trip - 5%


LAL/H-124 Oil Level Low/High Level Alarm Low - 20%High - 60%

LALL-129 Low Low Produced Water Level

Trip

- 25%


LAL/H-128 Produced Water Level Low/High

Level Alarm

Low - 20%

High - 80%

PAHH-134 High High Pressure Trip - 75 psig


PAH-136 High Pressure Alarm - 60 psig


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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 separatorsmust be pressurised with hydrocarbon gas from the ADGAS HP and LPsystems before crude oil can be re-introduced to the vessels.

Once the HP separator is pressurised to the normal operating pressure of250 psig, the shutdown inputs are temporarily bypassed to allow the inletshutdown valve for the vessel to be reset to the open position.

The level controllers are reset to Local Control before crude is introduced tothe HP separator. Once the choke is opened to introduce crude to the HP

separator and operating conditions have stabilised in the vessel, thecontrollers can be reset to Auto Control with normal setpoints. Theshutdown 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 inautomatic mode and controlled from the DCS. The operating pressure of theHP 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 formaintenance or as a routine operation.

To shutdown one of the vessels, the choke valve or manual isolation valveon 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 theother separators must be checked. This is to ensure that the separators nowin service can process the extra crude.

The level controllers for the vessel are now switched to Local Control andthe operating levels in the vessel reduced to a minimum.

To avoid gas blow-by the operating levels in the vessel must not be reducedbelow the low low level trip points.


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Once the operating levels in the vessel are just above the trip points, theshutdown valve on the inlet line must be closed from the local field panel toisolate 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 followingshutdown valves located in the respective separator inlet line:

SDV-100 (HP separator No 8)







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

SDV-120 (LP separator No 9)


SDV-200 (LP separator No 13) SDV-240 (LP separator No 15)




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 separatorsand gas-freeing prior to man entry.

7.2 NITROGEN

Nitrogen is available at each of the HP and LP separators to be used inpurging operations. Prior to start-up the separators are purged to atmosphereuntil the oxygen content in the vessel is less than 2%. The purging processmust be successfully completed to inert the vessels prior to the introductionof any hydrocarbons.

7.3 CORROSION INHIBITOR

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


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