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SECTION 3 THREE-PHASE SEPARATION 1
Introduction 1.1
Separator Types
2
Flow Patterns
3
Separator Internals
4
Principles of Separation
5
The Separation Process 5.1
6
Inlet Separation
Separation Systems 6.1
Production Separators
7
Separator Instrumentation
8
Separator Control
9
10
8.1
Pressure Control
8.2
Level Control
Process Shutdowns 9.1
Planned Shutdown
9.2
Startup Procedure
9.3
Startup After Emergency or Short-term Shutdown
High Pressure Relief Valves
Figures 3.1 3.2 3.3 3.4 3.5 3.6
Three-phase Horizontal Separator Vertical Separator Internals Three-phase Separator Internals The Separation System Production Train Separator and Instrumentation Separator Pressure Control
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1
INTRODUCTION A separator is a vessel in which a mixture of fluids, that are not soluble in each other, can be segregated. On offshore installations, separators are used to segregate gas from liquid, or one liquid from another such as water from oil.
1.1
Separator Types Separators are classified in two ways: • •
By the position or shape of the vessel By the number of fluids to be segregated
The following two vessel shapes are commonly used: • •
Horizontal - as shown in Figure 3.1 Vertical as shown in Figure 3.2
The number of phases refer to the number of streams that leave the vessel, not the number of phases that are in the inlet stream. For separation of gas and liquid, the separator is referred to as a two-phase type. For separation of gas, oil and water, the separator is referred to as a threephase type. Some wellstreams contain sand or other solid particles which are also removed in a separator. To achieve this, special internal devices are provided in order to collect and dispose of these solid materials such as sand, hence the term sandwashing of the separators.
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2
FLOW PATTERNS The flow in both horizontal and vertical separators is similar for two-phase separators whereby the mixture enters at the side or end of the vessel, the lighter fluid (usually gas) passes out at the top, and the heavier fluid is withdrawn at the bottom. Flow in a three-phase separator is shown in Figure 3.1; the fluid entering at one end of the vessel and the liquids being allowed to settle out at the lefthand side of the vessel. The oil layer floats on top of the water layer and spills over the weir into the oil chamber, where it is withdrawn under level control. The water layer remains on the left-hand side of the weir and is withdrawn under separate level control. Problems can, and do, arise with the interface level control between the oil and water layers usually due to an emulsion of oil and water at the interface. This type of problem can normally be overcome by using demulsifying agents, chemicals that break down emulsions, in order to give cleaner separation of the fluids.
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3
SEPARATOR INTERNALS A wide variety of mechanical devices are used inside separators in order to improve their efficiency and operation (refer to Figure 3.3). Those most commonly used are as follows: (1)
Deflector Plates or Diverters A deflector plate is used in gas-liquid separators and placed in front of the inlet nozzle of the vessel. The plate can be flat or dished, and as the inlet stream strikes it, the liquid falls to the bottom and the gas flows around the plate. In a vertical type vessel, the deflector may divert the stream around the walls of the vessel in order to create a centrifugal action.
(2)
Mist Pads Mist pads are most frequently used within gas-liquid separators to remove the vapour mist from the gas. The pad is made of closely woven wire mesh and is typically 4 to 8in thick. It is held in place by a sturdy grid frame which prevents it from being swept out or torn by a sudden surge of gas flow.
(3)
Coalescing Plates There are several configurations of coalescing plates and they are available from different vendors. They are used in gas-liquid vessels to remove liquid from the gas by causing small droplets to combine into larger drops which will separate more readily.
(4)
Straightening Vanes Typical of those used on Shell installations is the “Schoepentoeterl” type. These allow the use of smaller vessels, which are just as efficient as the larger vessels with longer residence times. Straightening vanes are installed to reduce turbulence. They are also used in gas-liquid separation vessels and installed when hydrate formation or paraffins would prevent the use of mist pads due to blocking etc.
(5)
Filter Elements Filters are used to remove mist from the gas in oil-water vessels. The separator usually contains an access hatch in order to allow replacement of the elements.
(6)
Centrifugal Devices These are used in gas-liquid separators. They impart a swirling action to the inlet stream that concentrates the flow of the liquid phase onto the wall of the device.
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Horizontal Baffles These are used in gas-liquid separators in order to prevent waves forming within the liquid phase. They are normally located near to the liquid level in the vessel.
(8)
Vortex Breakers It is normally a good idea to include a simple vortex breaker or liquid draw-off nozzles in order to prevent a vortex from forming, which could result in some gas being drawn out through the liquid line.
(9)
Water Jets Water jets are sometimes referred to as sand jets. Their purpose is to spray the sides and bottom of the vessel with a high pressure stream of water in order to remove sand and other solid particles from the walls and base of the vessel.
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PRINCIPLES OF SEPARATION Two factors are necessary for separators to function properly: (1) The fluids that are to be separated must be insoluble with each other ie they will not dissolve with each other.
(2) The fluids must not be of the same mass, ie they must be different in density. Separators depend upon the effect of gravity to segregate the fluids, if the fluids are soluble in each other, no separation is possible by gravity alone. For example, a mixture of distillate and crude oil will not separate in a vessel because they will dissolve together. They must therefore be segregated in a distillation process. Since a separator depends upon gravity to separate the fluids, the ease with which two fluids can be segregated depends upon the difference in the density or weight per unit volume of the fluids. Gas weighs far less than oil for the same volume, and will therefore separate within a matter of seconds. However, although oil is lighter than water, there is not such a marked difference in weight and separation of oil and water can take several minutes. (A typical specific gravity for oil is 0.84, which means that a given volume of oil would weigh 84% as much as the same as water.) Therefore the primary factor that affects separation of fluids is that of the difference between their densities.
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THE SEPARATION PROCESS The separation of oil, gas and water from each other is largely achieved by one or both of the following: • •
Physical separation Flash separation
Physical separation of liquids, solids and gases can be achieved naturally in a number of ways including: • • •
• • •
Settling of solids and layering of liquids through differences in densities Coalescence Filtration Velocity changes Centrifugal forces Impingement
Flash separation of gas and water vapour from the liquid phase is achieved when the well fluids mixture is discharged into a vessel at: • • •
A reduced pressure A higher temperature With an enlarged volume
The effect of all of these processes can be optimised by ensuring that: •
•
•
The equipment design incorporates features to make use of as many as possible of the above separation processes The separation equipment has been sized to accommodate the peak anticipated flowrates Sufficient time is allowed for the separation process to take place efficiently
A three-phase separator is illustrated in Figure 3.3. The up per section of the vessel is designed to separate gas from the liquid, while the lower section is designed to collect and degas the oil, and to separate oil and water by gravity separation, so that the three phases can be discharged from the vessel separately, each in a relatively clean state; it should be appreciated however that a three-phase separator will seldom produce water-clean oil and oil-free water.
Normally efficient separation of the oil, gas and water is achieved in a series of stages:
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5.1
Inlet Separation The bulk of the liquid-gas separation takes place in this section. The well fluid entering the vessel is subjected to a rapid and sudden change of direction and velocity, when it strikes an inlet momentum breaker or diverter plate. This redirects the mixture back against the dished end of the vessel which helps to minimise splatter and prevent the production of a mist of small particles. With the reduced operating pressure and enlarged space available, this results in the liberation of flash gas and an oil mist which rise, while the heavier slugs and large droplets of liquid fall to the bottom of the tank.
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SEPARATION SYSTEMS Separators are located downstream of the wellhead xmas tree, choke and production/test manifolds and provide the following functions: • • •
Clean-up/test separation Test separation Production separation (bulk)
Clean-up/test separators are used in the initial stages of well production when the flow of oil is likely to be contaminated with mud and sand. Test separators are used to test the flow of individual wells and are instrumented to measure flow of oil, water and gas. Production separators form an integral part of the production train. As the capacity of a separator is limited, it may be necessary to have a number of separators to handle the well fluid flow. Also it will be seen that the most effective form of separation may be in stages so there could be two, three or even four separators in series; each of these groups of separators is known as a train.
6.1
Production Separators Most platforms in the North Sea produce water in varying quantities which are expressed as a percentage of the liquid to storage. This water percentage is called the water cut and if a platform is producing oil into storage with a water cut of 13% then there is 87% oil going into storage. On gravity platforms, that is, platforms with subsea storage facilities, the water flows through the train into the storage cells where the water settles out leaving dry oil to be exported. Provided the separators are not overloaded and the design throughput of the process train can be maintained, this is the better mode of operation. However, circumstances can dictate that three-phase separation is required.
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Figure 3.1 shows a simplified sketch of a typical three-phase separator. The difference between two and three-phase separators is that on the threephase separator: • •
A weir is fitted An additional level indicating controller (LIC) and level control valve (LCV) are fitted
The weir forms a dam which creates a section where the water can separate out of the oil. The water falls to the bottom of the separator with the drier oil on top which flows over the top of the weir into the oil section. In this example the oil level is controlled by the LIC-2 and its associated LCV. On the upstream side of the weir LIC-1 and its LCV are controlling the level of the water. The controller is often at the interface level where the oil and water meet. The interface is not a clear division of oil and water but an emulsion of the two. Emulsion is one of the main problem areas of threephase control in that it makes interface level control difficult. Two sightglasses are fitted to a three-phase separator; one to show the interface level and the other the oil level. An example of an oil level gauge or sightglass is shown in Figure 3.3.
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SEPARATOR INSTRUMENTATION Within the limits of design and construction all separators have the same basic instruments and controls as follows: (1)
Pressure Indicator (PI) Monitors the pressure in the separator with readout both locally and remotely, the remote readout being transmitted to a central location such as the Central control room (CCR) or local equipment room (LER).
(2)
Temperature Indicator (TI) Monitors the separator temperature, again indicated both locally and remotely.
(3)
Pressure Safety Valve (PSV) Relief valves are installed on each separator, one in service and the other isolated. The relieving pressure is set, tested and certified at an authorised centre. No alteration to this setting is allowed after the relief valve has been certified.
(4)
Manual Blowdown Line This gives the facility to manually depressurise the separator, the gas being routed to the flare system.
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Gas Outlet Line This is split into two streams - the gas to the recompression and treating section and the gas to flare.
(6)
Pressure Indicating Controller (PIC) and PCV These two instruments control the separator pressure. The PIC monitors and modulates the PCV as required.
(7)
Gas Off-take Flowmeter This measures the volume of gas flowing from the separator in both flare or recompression mode. Generally this flow is a remote readout in the control room on both indicator and recorder.
(8)
Level Indicating Controller and Level Control Valve The LIC monitors the level and modulates the LCV to control the level at the setpoint. This is another instrument which gives local and remote readout in the control room.
(9)
Oil Outlet Line This line, which has the LCV in it, leads the oil to the next link in the process train which could be a lower stage of separation, storage or transfer pumps.
(10)
Drains This gives the facility to manually drain down the separator through the closed drain system.
A typical production two-phase crude oil separator is shown in Figure 3.5.
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SEPARATOR CONTROL All separators are fitted with the following protection facilities: •
Low level alarm
•
Low level shutdown
•
High level alarm
•
High level shutdown
•
High pressure alarm
•
High pressure shutdown
•
High pressure relief valves
•
In order to give added safety by preventing gas blowby between separators, a shut off valve is fitted to the pipework connecting the vessels. This valve is designed to close on a Low Low level being detected in the upstream vessel, or a high pressure being detected in the downstream vessel.
Should either/both of these conditions be d etected, then excessive pressure from an upstream vessel will not be communicated to a lower pressure rated vessel. Where crude cooling is installed prior to the final-stage separator this can be fitted with: •
High temperature alarm
•
High temperature shutdown
•
High integrity protection system (HIPS) - this provides an alternative (electronic) means of shutdown as a backup to the high level shutdown systems on the separators
Regardless of what function is being monitored the sequence for alarm and shutdown is the same. The first notice is the alarm allowing the operator to take corrective action. If no corrective action is taken or the action is ineffective further deterioration occurs and a shutdown results. All level, pressure or temperature shutdowns normally result in the closure of all of the producing wells' upper master gate (surface safety valves) and flow wing valves.
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8.1
Pressure Control When the gas recompression and treating facilities are operating, the gas from the separators flows directly to them; separator pressure being controlled by the backpressure in the downstream gas plant. Figure 3.6 is a diagram of a four-stage separation system and shows typical operating pressures at each stage. Separator pressure control varies depending on the operating mode but the first-stage separator will always be gas stream flow pressure. Pressure in the other separators is designed for stable operation of the gas compressors which compress gas from the second, third and fourth-stage separators. The PICs on each separator will be set slightly above the pressure the gas plant is holding on them. If the gas plant fails to take all of the gas from one or more of the separators, the pressure in those vessels will start to rise. As soon as it reaches the pressure setpoint the controller opens the PCV to route the excess gas to the flare.
8.2
Level Control The control of the oil level in the separator is the same regardless of whether gas is being recompressed or flared. Each separator has a level control system which regulates the position of a control valve in the oil outlet line. If the level rises, the controller opens the control valve; conversely, the valve closes when the level falls.
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PROCESS SHUTDOWNS During startup and shutdown, equipment and pipework are subject to additional stresses and strains from expansion and contraction. Where possible, action to prevent an emergency shutdown, for example, cutting back production to avoid high level trip, is good operating practice. A shutdown may still be required to cure the fault but it can be planned, as can the remedial action, so minimising the shutdown time.
9.1
Planned Shutdown Where a shutdown is planned it should be carried out in a manner which creates the least disturbance and shocks to the process and also to the reservoir. Wells should be closed in slowly using the chokes prior to closing their surface safety valve (SSV). The reason for shutting down will determine whether the train can be left pressurised and undrained or if maintenance is to be done. In this case, the separator train must be depressurised, drained and isolated. All isolations must be logged to ensure the train is correctly deisolated prior to startup.
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Prior to restart after an emergency shutdown, not only must the cause of the shutdown be cured but also the fault which created the cause. For example, a high pressure trip would require that the high pressure be bled off and the fault which caused the high pressure cured before restarting.
9.2
Startup Procedure Before any startup, pre-start checklists will be used by operations to ensure that all systems are in a state of readiness. These checklists will include the following: •
•
All utilities, including hydrate inhibitor, chemical injection, flare systems (HP and LP), closed drains and produced water, are to be available at the “battery limits” Pressure purging with nitrogen up to a pressure of 2 barg at the initial startup or following maintenance work where the system is air filled until an oxygen content of 3% is achieved
•
Locked and interlocked valves are in their normal operating position
•
Spectacle blinds and spades are in their normal startup position
•
•
•
•
In line block valves are in the correct position as per the valve position schedule in the operating manual All instrumentation is fully commissioned, checked and ready for service ESD systems are to be at process level startup status Power generation and distribution are to be at normal status, with switchgear racked-in and deisolated
•
Safety detection and protection systems are to be at normal status
•
Control valve handwheels are disengaged
•
•
At least one main oil line booster pump and one main oil line are ready for startup A series of operational checklists for verification of pre-startup requirements will be available for each system and subsystem The importance of good communications between all involved sections must be of the highest quality at all times, particularly at this startup stage.
NB •
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Commence wellhead fluid flow into the first stage of separation from the wellheads and manifold section
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•
•
•
•
•
•
9.3
Continuous visual checks for leaks are obviously most important at this critical stage as pressure and temperatures increase to their normal operating conditions Separator off-gas will be flared initially. Flares should have been nitrogen purged and pilots commissioned prior to initial flaring Gas compression feed valve remains shut until the HP gas system is brought into operation When the interface level exceeds the low trip setting, reset the shutdown valve to commence water treatment by routing produced water to the water treatment facilities When the oil level exceeds the low trip setting reset the shutdown valve thus allowing oil to flow to the next stage of separation As levels are established throughout the separation train the export pumping facilities are brought on line and oil flow through the plant stabilised As soon as conditions are stable, chemical injections such as scale inhibitor, corrosion inhibitor, demulsifier etc are commissioned
Startup After Emergency or Short-term Shutdown Startup after emergency or short-term shutdown follows the same procedure as startup after a prolonged shutdown, except for those items not applicable. For example, after an emergency shutdown all manual block valves will still be open. The fault which caused the shutdown must be rectified prior to opening up the well SSV.
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Figure 3.1
Figure 3.2
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Figure 3.3
1) Inlet Divertor 2) Vapour Mist Pad 3) Coalescing Plates 4) Straitening Vanes 5) Weir Plate 6) Gas Outlet 7) Vertical 8) Vortex Breaker 9) Sand Jetting Facility
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Figure 3.4
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Figure 3.5
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Figure 3.6
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