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INTRODUCTION

TO

BASIC OPERATIONS

IN THE

OIL & GAS INDUSTRY

3. OIL & GAS PRODUCTION,

SEPARATION & GAS DEHYDRATION


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CRUDE OIL & NATURAL GAS PRODUCTION, SEPARATION & GAS DEHYDRATION

TABLE OF CONTENTS

PAGE SUBJECT

2SECTION 1: Introduction - Origin & Production of Crude Oil & Natural Gas Xmas Trees & Flowlines

6 Well Test Separator

7 Wells, Wellheads & Reservoir Basics

10 Restoration of a Depleted Well

12 Gas Lift Operations

19 SECTION 2: Separators Principles, Functions & Operation

26 Separator Types & Control

39 SECTION 3: Natural Gas Dehydration - Process, Equipment & Regeneration

60 Operating problems and Glycol care

Compiled, Illustrated and Produced by:

Norman Wiltcher. Senior Technical Instructor (Oil & Gas Production & Processing) (Retired).


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SECTION I

OIL & GAS PRODUCTION & SEPARATION

INTRODUCTION

The Origin of Crude Oil & Natural Gas

Many people believe that crude oil and natural gas are contained in huge cave-like structures deepunderground. Geological studies of sedimentary rocks indicate that oil originated during the depositof dead marine organisms together with sand, silt and other sediments which formed the rocks underthe sea beds. The formation of layers of rocks continued to take place and to build up containing theorganic matter of the marine organisms and to create high pressure and temperature. In the absenceof oxygen, and under the effect of the combined factors of pressure, temperature, catalysis and time,the chemical components of these marine substances have undergone break-down andtransformation into HYDROCARBON compounds trapped in small pores (pockets) in the rocks, theresult of which was the formation of crude oil and natural gas within the rocks.

Migration of Oil, Gas and Water

While the oil and gas were forming in the rock beds, it also tended to move (migrate) in an upwarddirection. This takes place from the source bed rocks through permeable porous rocks. Water, Oil &Gas move under the same forces, but in slightly different directions, Gas is much less dense than oil,and oil is less dense than water, so there is tendency for the gas and oil to move upwards through thewater.

This upward movement of the components (water, oil and gas) continues, until the petroleumbecomes trapped under an impermeable layer (or Cap Rock). It then flows along under thisimpermeable cap layer, until it reaches a position from which it cannot move any further, andbecomes trapped. Migration continues and the Oil and Gas build up pressure under the cap rock. Oiland gas may also be trapped by another formation like a fault, which has a non-permeable surface.

The Reservoir (See Simplified example of a reservoir formation on page 2).

The known forms of petroleum accumulations are classified as folds, anticlines and stratigraphictraps; these are known as structural traps or reservoirs. About 80 or 90 percent of known petroleumreserves occur in such traps which have the following characteristics :-

a). It should be of sedimentary origin.b). The rock must be porous and permeable.c). The reservoir must be capped by a non-permeable bed.


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SIMPLE DRAWING OF A 'TRAP' TYPE RESERVOIR

Most of the worlds oil occurs between depths of about 600 and 3000 meters. Gas tends to occurdeeper than oil and it is more stable at higher temperature and in some cases, it is a primary productin the source rock.

WATER

GAS

OIL

WELL BORE


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DRILLING

When a reservoir is identified, the geological forecast for a well will be issued with the expectedformation boundary, the unstable beds that could make difficult drilling, the depth of the well and

the possibility of oil and gas in the reservoir.

On the basis of this forecast, a drilling point is located, and a planned schedule is prepared includingmaterials and estimation of time and cost. The main components of drilling equipment are made of aBit, Kellys or Drill-collars (heavy sections of drill pipe), Rotating table, Mud injection systems andother utilities.

CHRISTMAS TREE

The final act of drilling is to fix an assembly of valves onto the casing head of the well. This assemblyis called a Christmas Tree (Xmas-tree). As one valve is not enough to control oil flow, at least twovalves are needed.

The first one is called the Master Valve which is normally kept open and is used only when thesecond valve fails to operate or when under maintenance.

FLOW LINES

The lines that carry the three-phase flow - (water, oil and gas) from the wells to the productionmanifolds, are called 'Well Flow Lines'. There may be more than a hundred wells in one field allpiped to a Field Production Manifold. The production manifolds then transfer the three phase liquid

to the GOSP (Gas Oil Separation Plant) via a single flowline. The well flowlines will have variousinstruments fitted and provision for anti-corrosion chemical injections. In some cases, well flowlineshave a 'Choke' which governs the maximum flow from the wells in order to prevent high velocityflow causing erosion of equipment.The manifolds normally have Production and test flowlines and a blowdown header

(See Pictures on the following pages)

The produced fluids often contain acid gases like Hydrogen Sulphide (H2S) and Carbon Dioxide

(CO2). To minimise corrosion, an inhibitor will be injected into the well flowline.


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Typical Oil Well Christmas Tree

Field Manifold with Production & Test Flowlines

CORROSION

INHIBITOR

TO PRODUCTION

TO BLOWDOWN

TO TEST


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3

2

1

7

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From Field Manifold

Well Test Separator

In the above picture the numbers indicate the following:-

1. Start-up Charge Control Valve2. Main Inlet & Control Valve3. Produced Gas Metering (Daniel Type Orifice Meter)4. Separator Pressure Control Valve5. Oil Level Controller (Displacer & Torque Tube)6. Water Level Controller ( " " )7. Water Drain to Pit & Vessel Blowdown Line8. Safety Valve (Set at 1.5 x Normal Operating Pressure)

Note: The Oil & Water outlet lines are on the other side of the Vessel.


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TYPES OF WELLS AND RESERVOIRS

Crude oil and natural gas reservoirs are found in rock formations called 'Anticlines, Traps, Faults

etc', below the surface of the earth and the well is drilled into these formations. A pipe is then run intothe hole to allow fluid to flow to the surface. Smaller diameter casing strings (pieces of pipesconnected to each other) are set in the well string (if needed for operational reasons). Finally theproduction or oil string. The depth that each string is set, is determined by special conditions at thewell site.

Wellheads and Flowlines

A wellhead is the equipment at the surface which controls the well. It is usually made of cast orforged steel and machined to a close fit to form a seal and prevent well fluids from blowing (orleaking) at the surface. The wellhead is sometimes made up of many heavy fittings with certain partsdesigned to hold up to 30,000 Psi.

The wellhead is formed of combinations of parts called: -

1) Casing Head. 2) Tubing Head. 3) Xmas tree. 4) Gauges.

Where production and pressure are very low, a simple wellhead may be used.

A choke valve is used to control the gas flow for gas lift wells. A choke may also be used in theproduction line at the separation facility or on the wellhead to control fluid flow.

1. CASING HEAD

During well drilling as each piece of pipe (string) of casing is run into the hole, it is necessary to installheavy fittings at the surface to which the casing should be attached. The casing head usuallyprovides some kind of gripping devices to hold the weight of the casing, it acts as a support for thecasing string, and also provides the connections at the surface for controlling the flow of fluids.

2. TUBING HEAD

The most important purposes of the tubing head is to :

1. Support tubing strings.

2. Seal off pressure between casing and tubing.

3. Provide connections to control flow of fluids.

The tubing head is supported by the casing head.


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3. THE XMAS TREE

This consists of the equipment required for the control of the well: -

1. Master Valve - Generally, two master valves are installed both of which is open duringproduction. The reason for two valves is that, should one valve fail (jam) in the open position,the other can be used to isolate the well in an emergency.

2. Wing Valve - This is usually used for production from the tubing and may be followed by achoke for control of production.

3. Crown Valve Used for well servicing Wireline operations: - Installing/removing gas liftvalves, well surveys: - Downhole pressure & temperature gradient measurement Etc.

4. Pressure/Temperature gauges for operational checks.

Figure: 1

TUBING PRESSURE

CROWN VALVE

WING VALVES

MASTER VALVES

CASING VALVES

TUBINGHEAD

SURFACECASING

GROUND

LEVEL

CELLAR

XMAS TREE

WELLHEAD


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Figure: 2 - Natural Flow Oil Well on Production from the Tubing

During the early life of a well, the high pressure fluids in the reservoir flow through the formation tothe bottom of the well bore, then pass to the surface via either the tubing or casing (annular space) tothe surface using it's own pressure energy.

Before a well is drilled into a reservoir, the well fluids are static, once a well is drilled into a reservoirthe static fluids begin to flow to the surface.

When the well is not producing or shut in, the fluids are static, giving what is known as the 'StaticBottom Hole Pressure' (SBHP) (reservoir pressure).

When the well is opened up, the bottom hole pressure will decrease due to the flow of fluids to thesurface.

HIGH / LOW PRESSURE

SHUTDOWN VALVE

BLOWDOWN

TO PRODUCTION

MANIFOLD

VARIABLE CHOKE(FLOW CONTROL)

FLOW ELEMENT

LOCAL FLOWRECORDER


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This is known as the 'Flowing Bottom Hole Pressure' (FBHP). For a well to flow, a pressuredifference (DP) must exist between the actual reservoir pressure and the bottom hole pressure.

This DP between the SBHP and the FBHP is known as 'Drawdown'.

The greater the drawdown, the greater will be the well productivity. The surface equipment backpressure plus the pressure exerted by the depth of the column of fluids will govern the FBHP.

When the pressure in the reservoir becomes equal to this pressure, i.e., drawdown = zero, then theflow stops and the well is termed as 'Dead'.

RESTORING A DEPLETED WELL

Many wells, due to depletion of reservoir pressure, can no longer be produced by natural means. An

artificial lift system is used to maintain production of these wells. One system may be the installationof a down-hole pump.

Another system used is 'Water Flood' where injection of water into the drive water table by way of anumber of water injection wells placed at strategic points around the position of the oil producingwell(s).

The injected water is obtained from a different water table to that which is the drive water table forthe oil wells. This increase in the water level in the drive water pushes the oil to the surface.

A widely used system is that of 'Gas Lift' where high pressure gas supply is injected into the

production string through special gas lift valves.The gas lift process is the method we will discuss later.

As stated earlier, the oil, gas and water produced by whatever method, will be piped to 'FieldManifolds' where a number of wells can be fed into a single production line feeding the 'GOSP' - Gas,Oil Separation Plant where the required well products of oil & gas are separated and treated asrequired while the water is drained away to disposal or may be used as injection water as describedearlier.

Figure: 3 Shows a typical field manifold


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Figure: 3


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THE GAS LIFT PROCESS

RESTORING A WELL'S PRODUCTION

The illustration (Figure: 4), shows a simplified idea of the formation of petroleum within a fold deepunder the earth's surface and the effects of drilling a well into it.

It should be borne in mind that the fluids are not contained in a 'cavern' type basin, but are held bythe pores of the rocks forming the permeable sedimentary layers of the strata and trapped there bythe overlying layer of impermeable cap rock, (often a salt dome).

Figure: 4

Here the Static Bottom Hole Pressure (SBHP) is 3,100 psi and the Flowing Bottom Hole Pressure

(FBHP) is also 3,100 psi. There is no DP i.e. no 'Drawdown'. The well is not producing and isclassed as 'Dead'.

The following illustrations show a natural flow producing well, a dead well and the process of gas liftas applied to the dead well.

The diagrams are simplified for ease of understanding and are accompanied by notes.

WATER

GAS

3,100 PSI

OIL

3,100 PSI

WELL BORE


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Figure: 5

The illustrations above are explained in more detail on the following pages.

WELL ON NATURAL 'DEAD' WELL WELL ON GAS-LIFTFLOW NO FLOW PRODUCTION

TO PRODUCTION TO PRODUCTION

WELLHEAD

CHOKE

GAS-LIFT GASINJECTION

TUBINGFLOW

CASING ANDTUBING LEVELS

1st GAS LIFTVALVE

CLOSED

2nd GAS LIFTVALVE

CLOSED

3rd GAS LIFTVALVE OPEN -

- OPERATING VALVE

CASING

LEVEL

NOFLOW

FBHP = 3,100 psi CASING & TUBING EACH FBHP = 2,700 psiSBHP = 3,500 psi AT 3,100 psi SBHP = 3,100 psi

DRAWDOWN = 400 psi DRAWDOWN = ZERO psi DRAWDOWN = 400 psi


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UNLOADING THE WELL

Figure: 6, above, shows a gas lift well where injected gas has begun to force down the liquid in thecasing and uncovered the first special gas lift valve. The gas entering the tubing effectively decreasesthe density of the liquid and thereby decreases the head pressure within the tubing. This actioncontinues and further gas lift valves are uncovered allowing more gas to enter the tubing furtherdecreasing the liquid density in the tubing and therefore increasing the drawdown. Production fromthe well is slowly being re-established. (FIGURE: 8)

PACKERS

FLUIDS BEGINNING TOFLOW THROUGHPERFORATIONS.

DRAWDOWN AT 50 psi

FBHP 3,050 psi FBHP 2,900 psi

FLUID FLOW INCREASINGAS MORE GAS ENTERS

TUBING.

DRAWDOWN NOW AT 200 psi

SBHP 3100 psi

G/L VALVE

OPEN. GAS

ENTERS TUBING

G/L VALVEOPEN

G/L VALVEOPEN

G/L VALVEOPEN

G/L VALVE

CLOSES

G/L VALVE

OPENS

G/L VALVEOPEN

G/L VALVE

OPEN

CASING FLUIDLEVEL DECREASING

G/L GASINJECTION

G/L GASINJECTION

TO PRODUCTION

DECREASING TUBINGFLUID DENSITY

Figure: 6


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The unloading of the well continues as in Figure: 7 and production is increasing as drawdownincreases. Note that the upper gas lift valves have now closed and the injection gas is passingthrough valve No. 3. This occurs because the valves are constructed with a nitrogen filled bellows.

While the valve is immersed in the casing liquid, the combined pressure of the injection gas and theliquid head will keep the valve open thus allowing the casing liquid to pass through the valve into thetubing.

DRAWDOWN INCREASINGNOW AT 300 psi

FBHP 2,800 psi FBHP 2,700 psi

DRAWDOWN NOW AT 400 psiWELL PRODUCTION AT

DESIRED LEVEL

ValveClosed

Valve

Closed

ValveOpen

ValveOpen

ValveClosed

ValveClosed

ValveClosed

Valve Open(Operating Valve)

SBHP 3,100 psi

INJ. GAS

PRODUCTION

Figure: 7

PRODUCTION

INJ. GAS


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This process continues until the supplied gas lift gas can no longer decrease the level in the casing.At this point the last valve to be uncovered will become the 'Operating Valve' and the well is back onnear normal production. The operating valve is not necessarily the bottom valve of the system. Thefollowing picture is of a gas lifted well producing from the casing (or annulus) with injection gas into

the tubing. The principle of operation is the same as previously discussed with some differences inthe gas lift valve arrangements.

Well Producing on Gas Lift to the Tubing and Production from the Casing

Figure 8 on the following page shows a gas lifted well with the gas lift gas injection into the casingand production from the tubing.Note the gas lift gas metering unit and the choke control valve. Also note the injection of methanolinto the gas lift gas.This is to prevent freezing of any small amounts of water in the gas when the gas lift gas is pressure-reduced across the choke valve. Such icing within the choke would cause problems with the systemand, as these well locations are generally remote, the arrival of an operator to solve the problem maytake some time. Meanwhile, production would suffer losses.

Gas lift gas injection to tubing

Xmas Tree

Production from CasingProduction from Casing


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Figure: 8

Figure: 9 on the following page, is a diagrammatic example of a gas lifted well with the gas lift gasinjection into the tubing and production from the casing.

INJECTION GAS

F.R. (FLOW RECORDER)

P.R. (PRESSURE RECORDER)

METHANOL(ANTI-FREEZE

INJECTION)

Pump

VARIABLE CHOKE

BLOWDOWN

BLOWDOWN

PRODUCTION LINE

TOGOSP


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Figure: 9 - Gas lift gas to tubing - casing production

When a reservoir has been drilled (a number of wells may be drilled into the same formation), thewell flowlines are fed to a manifold. This may be situated out in the field if the wells are somedistance from the process facility. In this case, the production from many wells will be fed into asingle production line to the plant facility. Other nearby wells may be piped to the plant eitherdirectly into a separator or to an inlet manifold feeding a bank of separators.

ANNULAR (CASING) PRODUCTION

OPERATING VALVE(UPPER VALVES

CLOSED)

'BULL' PLUGGEDTUBING

INJECTION GAS

PRODUCTION


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SECTION II - SEPARATION & SEPARATORS

SEPARATOR FUNCTIONS

INTRODUCTION

A SEPARATOR is a vessel in which a mixture of immiscible fluids are separated; e.g. Crude oil,Natural gas and Water. A separator may be a 'Horizontal', 'Vertical' or 'Spherical' vessel andgenerally consists of the following :-

1. A primary separation section to remove the bulk of the liquid from the gas.

2. Sufficient liquid capacity to handle surges of liquid from the line.

3. Sufficient length or height to allow the small droplets to settle out by gravity (toprevent undue entrainment).

4. A means of reducing turbulence in the main body of the separator so that propersettling may take place.

5. A mist extractor to capture entrained droplets or those too small to settle bygravity.

Where a vessel is simply separating total liquid from gas, it is called a 'Two-Phase Separator' Whenthe process requires the separation of two liquids and a gas, the separator is called a 'Three-PhaseSeparator'. 'Two or Three Phase separation', refers to the number of streams leaving the vessel andnot the inlet fluid stream.

Petroleum as produced from a reservoir is a complex mixture of hundreds of different compounds ofhydrogen and carbon, all with different densities, vapour pressures, and other physicalcharacteristics. A typical well stream is a high velocity, turbulent, constantly expanding mixture ofgases and hydrocarbon liquids, intimately mixed with water vapour, free water, solids, and othercontaminants.

As it flows from the hot, high pressure petroleum reservoir, the well stream is undergoing continuous

pressure and temperature reduction. Gases evolve from the liquids, water vapour condenses, andsome of the well stream changes in character from liquid to free gas.The gas is carrying liquid mist droplets, and the liquid is carrying gas bubbles.

The function of field processing is to remove undesirable components and to separate the well streaminto sellable gas and petroleum liquids, recovering the maximum amounts of each at the lowestpossible overall cost.


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Field processing of natural gas actually consists of four basic processes:

1. Separation of the gas from free liquids such as crude oil, hydrocarbon condensate,

water, and entrained solids.

2. Processing the gas to remove condensable and recoverable hydrocarbon vapours.

3. Processing the gas to remove condensable water vapour which, under certainconditions, might cause hydrate formation.

4. Processing the gas to remove other undesirable components, such as HydrogenSulphide and / or Carbon Dioxide.

WELL FLUIDS & WELL CLASSIFICATION

Fluid flow from a well can include gas, free water, condensable vapours (water or hydrocarbons),crude oil, and solid debris (basic sediment). The proportion of each component varies in differentwell streams.

When water is produced with crude oil, it is mixed in either or both of the following forms: -

1. FREE WATER: Water mixed with the oil but will separate easily into a clear layer whenthe mixture is allowed enough time to settle.

2. EMULSION: Water can also be mixed with the oil in the form of very small dropletsof water coated with oil. A mixture like this is called an EMULSION.Water in this case cannot be easily separated from oil.

As for the gas, it can be found in the well as: -

1. SOLUTION GAS: Gas dissolved in the well fluids under the effect of pressure of thereservoir.As the fluids flow from the reservoir into the well and up to the surface,the pressure of the fluid decreases.

The capacity of the liquid to hold gas in solution also decreases and gasstarts to separate out of the oil.

2. FREE GAS: Gas that is NOT held in the oil under reservoir conditions.

3. ASSOCIATED GAS: Total gas produced with the oil in a crude oil well.


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Wells are generally classified according to the type of fluid they produce in the greatest quantity. Themain three types of well are:

1. CRUDE OIL WELL: A well that produces mostly crude oil with varying proportions of

water, solution gas, possibly free gas and some solid debris.

2. DRY GAS WELL: A well that produces mostly gas with no crude oil (or liquid hydro-carbon). The produced gas can contain some water.

3. GAS CONDENSATE WELL: A well that produces both gas and light liquid hydrocarbon(condensate) and maybe some water, but no crude oil.

Much of the hydrocarbon condensate is very light, and changes from liquid to vapour at nearatmospheric conditions. Therefore, when they are produced from high-pressure reservoirs to asurface line at near atmospheric pressure, they vaporise.

Gas, which is produced from a well together with oil, is called 'CASING HEAD GAS' or'ASSOCIATED GAS'.

Gas produced alone or with water is called NON ASSOCIATED GAS.This gas is produced from both dry gas wells and gas condensate wells.

The following table shows well classifications, fluid compounds, and processing methods.

CLASS OFWELL

FLUIDS INRESERVOIR

FLUIDS INFLOW LINE

PROCESSING STEPS WHICHMAY BE REQUIRED

DRY GAS

GAS,

POSSIBLY WATER

GAS,

POSSIBLY WATER

SEPARATION,

GAS DEHYDRATION

GASCONDENSATE

GAS,POSSIBLYWATER

GAS CONDENSATE,POSSIBLY WATER

SEPARATION,GAS & CONDENSATE

DEHYDRATION

CRUDE OIL

CRUDE OIL,POSSIBLY GAS,

POSSIBLY WATER

CRUDE OIL,POSSIBLY GAS

POSSIBLY WATER

SEPARATION,GAS DEHYDRATION

Oil well fluids are produced normally in two phases - vapour and liquid. These two phases requireentirely different handling, measuring, and processing methods. Therefore, it is necessary toseparate the phases as soon as practical after leaving the wellhead. The basic equipment used for thispurpose is the OIL & GAS SEPARATOR.

Reservoir pressures are generally much higher than atmospheric pressure. As well fluids reach thesurface, pressure on them is decreased. The liquid ability to hold gas in solution decreases, and theliquids begin to release 'Solution Gas'.Light fluids begin to separate naturally when the pressure on them is lowered.The solution gas released as Free Gas is held by the surface tension of the oil.


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This free gas is released from the oil when the well fluids are warmed to reduce the surface tension ofthe oil. Gravity alone will eventually cause heavy components to settle out and light components torise.

In summary, there are variables which aid in the separation of a fluid stream.

1. Temperature of the fluids. 2. Pressure on the fluids. 3. Density of the components.

In addition to using the force of gravity, modern separators make use of other forces to get the bestpossible separation of oil and gas. The way in which each of these forces is used can be betterunderstood by following the flow of a mixture of oil and gas through a separator.

SEPARATOR FUNCTIONS

A wellstream separator must perform the following: -

A. Cause a primary phase separation of the liquid hydrocarbon from those that are Gas.

B. Refine the primary separation by removing most of the entrained liquid mist from the gas.

C. Further refine the separation by removing the entrained gas from the liquid.

D. Discharge the separated gas and liquid from the vessel and ensure that no re-entrainment of oneinto the other takes place.

If these functions are to be accomplished, the basic separator design must:

1. Control and dissipate the energy of the well stream as it enters the separator.2. Ensure that the gas and liquid flow rates are low enough so that gravity segregation and

vapour-liquid equilibrium can occur.3. Minimise turbulence in the gas section of the separator and reduce velocity.4. Control the accumulation of froth and foam in the vessel.5. Eliminate re-entrainment of the separated gas and liquid.6. Provide an outlet for gases, with suitable controls to maintain the required operating pressure.7. Provide outlets for liquids, with suitable liquid-level controls.8. If necessary, provide clean-out ports at points where solids may accumulate.9. Provide relief for excessive pressure in case the gas or liquid outlets should be plugged.

10. Provide equipment (Pressure gauges, Thermometers, and Liquid Level gauge assemblies), tocheck visually for proper operation.

Most platforms have a series of production separators, starting with a high-pressure separator, whichseparates the (HP) gas from the liquids. Liquids are then piped to a medium pressure (MP) separator,which removes more gas and then passes the liquids to a low pressure (LP) separator that removeseven more gas and then separates water from the oil.


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The water from the low-pressure separator is piped to a skim tank or to a drain pit, with the oil beingpiped to a metering and pumping station to be piped to other processes or storage tanks.

Well fluid separation depends on the composition of the fluids, and on their pressure and

temperature.

The pressure of the fluids is controlled by the back - pressure regulator and the temperature may beregulated by expanding the fluids through a choke, by addition of heat in a furnace or by heating orcooling in a heat exchanger. Therefore, separators can be designed to handle fluids according to thefluid composition.

Separators are built in various designs, such as horizontal and vertical. The internal structures of thevessel, to aid in the mechanical separation of the gas and liquids, are of a spherical design, dependingupon the manufacturer.

Although most separators are two - phase in design, separating the gas and total liquids, three - phasevessels can be built to separate natural gas, oil or other liquid hydrocarbons, and free water.

The main principles used to achieve physical separation of gas and liquids are: -

GRAVITY SETTLING and COALESCING

Any separator may employ one or more of these principles, but the fluid phases must be 'Immiscible'(cannot mix), and have 'Different Densities' for separation to occur.

GRAVITY SETTLING:

During the separation process, the gas is moving in an upward direction into the vapour section ofthe separator and the liquid particles are tending to fall to the vessel bottom under the influence ofgravity.

Gas will separate more quickly from a liquid when it is flowing 'HORIZONTALLY'.In a 'VERTICAL' separator, the gas is moving vertically upwards and the liquid droplets, due togravity, are falling vertically downwards. The contra-flow of the two fluids therefore interferes withthe flow paths and separation is slower.

Generally, because of the above factors, the vapour section of a Horizontal separator will be of a

smaller volume than that of a Vertical vessel.


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COALESCING:

Very small droplets such as fog or mist cannot be separated practically by gravity.However, they can be coalesced to form larger droplets that will separate out.

Coalescing devices in separators force gas to follow a tortuous path. The momentum of the dropletscauses them to collide with other droplets or with the coalescing device, forming larger droplets.These can then separate out of the gas phase due to the influence of gravity.Wire mesh screens, Vane elements, and Filter cartridges are typical examples of coalescing devices.

Separation vessels usually contain four major sections, plus the necessary pressure and liquid levelcontrols. These sections are: -

1. Primary Separation Section:

For removing the bulk of the liquid from the inlet stream. For example, free liquids, slugs and largedroplets. This is usually accomplished by a change in the direction of fluid flow, either by baffles ordeflection plates near the inlet nozzle or by using a tangential inlet nozzle as in 'Tangential Feed' or'Cyclone' separators which operate by centrifugal force being set up within the vessel.

2. Secondary Separation Section:

For removing the maximum amount of small liquid droplets without an elaborate design. The majorseparation principle in this section is by gravity settling of the liquid droplets from the vapour stream.

3. Mist Extraction Section:

For removing the maximum amount of tiny liquid droplets remaining in the gas stream. The mistextractor may be of the impingement type; (mesh pads) and/or may use the centrifugal forceprinciple; (the vane type).

4. Liquid Accumulation Section:

For receiving and disposing of the liquid collected.Sufficient volume and proper level control equipment should be provided to handle surges that mayoccur during operations.

The length of a horizontal separator has a greater effect on capacity than the height of a vertical type.In the horizontal vessel the path of any droplet ideally has a trajectory similar to that of a shell from agun. Therefore, the length required depends on: -

1. Droplet size. 2. Gas velocity. 3. Droplet density. 4. Vessel diameter. 5. Degree of turbulence


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In the above picture, the system consists of three separators - all are 3-phase separation vessels.

The 1st stage on the right, is the Low Pressure suction KO drum to a LP compressor, the 2nd stage (inthe middle), is the Medium Pressure separator - discharge from the LP compressor and, suction to theHP compressor. The 3rd drum, on the left, is the final separation stage for the HP discharge gas.Cooling stages are installed after each discharge.

Separated water is usually dumped to a disposal pit. The gas condensate will then be metered andpumped to further treatment facilities and, the gas will be metered and go on to further processingunits.

The following diagrams depict common types of separator.


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TYPES OF SEPARATOR

1. GAS / LIQUID SEPARATORS

A. The simplest type of Horizontal separator is shown in Figure : 10.

They are used to separate a two or three-phase inlet fluid into liquids and gas.The vessel inlet and gas outlet nozzles, consist of curved pipes which cause a change in direction ofthe inlet flow and the gas outlet. The liquid particles fall to the vessel bottom by gravity, while thegas rises to the top. This type of simple separator is not very efficient.

B. The 'Knock-Out Drum' is another simple type of separator as shown in Figure : 11.

It is used to separate a two or three phase inlet fluid into liquid(s) and gas.

The vessel inlet flow generally hits an inlet deflector plate to begin the separation process.Between the inlet and the gas outlet, some form of de-misting element may be installed which can bea wire mesh 'screen' or 'pad' or an angled vane type.

The demister construction presents a large surface area to the liquid mist entrained in the gas whichcauses small droplets of liquid to coalesce into larger drops which fall to the vessel bottom by gravity.The gas outlet nozzle exits the gas from the vessel above the demister screen

Figure : 10 - Separator

2 PHASEFLUID INLET

GAS OUTLET

LIQUIDS OUTLET

LIQUID LEVEL

GAS

HORIZONTAL TYPE


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Figure : 11 - K.O. Drum

FACTORS AFFECTING SEPARATION

The following table shows some of the factors that affect separation :-

SEPARATION FACTOR EFFECT OF THE FACTOR

1. Difference in Fluid Densities

2. Residence Time

3. Coalescing Element SurfaceArea

The greater the difference in densities, theeasier the separation.

The longer the fluids are in the separator, the

better the separation.

The greater the area of the coalescingelement, the better the separation.

VERTICAL TYPE

LIQUIDS OUTLET

LIQUIDS

GAS

GAS OUTLET

2 PHASEFLUID INLET

VERTICAL TYPE

LIQUIDS OUTLET

LIQUIDS

GAS

GAS OUTLET

2 PHASEFLUID INLET


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HORIZONTAL SEPARATORS

Figure 12, is a field separator labelled as an actual operating unit together with control systems (The'M's' are the inlet manifolds). After separation and metering, the oil and gas are re-combined andpiped to the main production line feeding the plant GOSP facility. This operation saves the need fortwo pipelines - gas and oil - to the main facility where they will be separated along with otherproduced wells.

Figure: 12 - Typical, Single tube, 3-Phase Separator and Control System.

METERED WATER TODISPOSAL

PDM

FI

PRODUCTION LINESFROM FIELDMANIFOLDS

M.1 M.2

INSTRUMENTGAS

LEGEND: M = Manifold. FT = Flow Transmitter. FI = Flow Indicator.TI = Temperature Indicator. PG = Pressure Gauge. PI = Pressure Indicator.

PIC = Pressure Indicating Controller. LIC = Level Indicating Controller.LI = Level Indicator. LG = Level Gauge (Glass). KO = Knock Out Drum (Separator).PSV = Pressure Safety Valve

DEMULSIFIER

M.5.

M.4

M.3

GAS

OIL

WATER

TO FLARE SYSTEM

S/V's PIC

PG

FR TI

S/V

KO

DRUM PICVPCV

LIC

LG LG

LIC

METERED OIL &GAS TO GOSP

TO DRAIN

PI

LCV

LCV

FI

3 PHASE FLOW


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Figure 13, Shows a typical horizontal, Single tube, 3 - phase separator internal arrangement.

Figure 14, Shows a Double tube, 2 - phase separator internal arrangement.

HORIZONTAL SEPARATOR

Figure: 13 - Typical Horizontal, Single tube, Separator Internals

OIL &WATER OIL

WATER

OILWATER

OIL

SAFETY VALVE CONNECTION

GAS OUTLET3 - PHASE

FLUIDINLET

WATER

OUTLETOIL

OUTLET

PRIMARYSEPARATION

BAFFLE PLATES

SECONDARYSEPARATION

BAFFLE PLATES

MIST

EXTRACTIONSECTION

INLET FLUIDDEFLECTOR


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Figure: 14 - Double-tube Horizontal Separator

LEGEND:

A: Fluid Inlet. B: Primary Separation Section. C: Secondary Separation Section.D: Liquid Down-pipes to Lower Tube. E: Gas Outlet. F. Liquid Outlet

UPPER TUBE

LOWER TUBE


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VERTICAL SEPARATORS

Figure : 15 - Typical Knock-Out Drum (3-Phase)

C. The Tangential or Cyclone Separator (Figures : 16 & 17).

This type operates by centrifugal force. It is used to separate a two or three phase inlet fluid intoliquid(s) and gas. The inlet flow enters the vessel side at a tangent to the circumference.

This causes the fluids to rotate at high speed inside the drum. The centrifugal force of rotation causesthe heavier liquid particles to be forced downwards while the lighter gases are forced upwards.

Again, a demister screen may be installed near the vessel top to coalesce liquid droplets from the gasand drop them back into the liquid.

GAS

DEMISTER PAD

PIC

PICV

LICV

LIC

LIC

LICV GAS OUTLET

HYDROCARBONLIQUID

WATER

LIQUIDS INTERFACE

H/C LIQUID OUTLET

3 PHASEFLUID INLET

FREE WATERTO DISPOSAL



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Some de-misters consist of 'Packing' type materials like 'Raschig Rings', 'Ceramic Saddles' or othersuitable materials. As seen in Figure: 17

Note: Demister screens can become fouled and lose efficiency. From time to time, it is necessary to

shut down the separator and remove the demister for cleaning or renewal.

Figure 16: Tangential or Cyclone Separator

2-PHASE FLUIDTANGENTIAL

INLET

GAS OUTLET

TOP VIEW

2-PHASE FLUIDTANGENTIAL

INLET

GAS OUTLET


LIQUID OUTLET

THE ROTATING, CENTRIFUGEACTION CAUSES THE HEAVIERCOMPONENTS (LIQUID ANDHEAVY MATERIAL) TO FALL TOTHE BOTTOM.

THE LIGHTER COMPONENTS ,(GASES), RISE TO THE TOP.


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Figure 17: Two-Phase Cyclone Separator

The two magnified drawings indicate 2 types of demister systems that may be used in separators.

A. Represents 'Conical Impingement' contacting devices.B. Shows a packed bed of loose 'Raschig Rings'.

Each type coalesces the droplets of mist entrained in the gas and, as they form larger droplets,they fall into the bottom liquid. (Droplet size is exaggerated)

GAS OUTLET

FLUIDINLET

TANGENTIAL

FLOW

LIQUIDOUTLET


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2. LIQUID / LIQUID SEPARATORS

This type of separator is referred to as a 'Coalescer' and is used to separate two immiscible liquids likehydrocarbon and water emulsions. Tiny water droplets entrained in the hydrocarbon liquid wouldtake a long time to separate out in a conventional separator.

The Coalescer vessel contains 'Filter' type elements, generally made of fibre-glass.As the mixed liquids pass through the elements, the heavier (more dense) water droplets are sloweddown and stick to the fibre-glass surfaces of the elements where, as more droplets collide with them,they coalesce into larger drops and fall to the bottom of the vessel and flow into a 'Boot' in the vesselbottom.

The lighter hydrocarbon liquid rises to, and leaves by the top, of the Coalescer.

The Coalescer is operated 'Liquid Full' and, should any gases be released during the process, they arevented to flare or fuel system by automatic 'Vent-trap' systems in order to maintain the liquid-filled

state of the vessel. (If gases were allowed to build up in the vessel, the liquid level in the vessel wouldbe forced down by the gas. This would gradually decrease the efficiency of the Coalescer operation).(See Figures : 18 & 18A)

Figure: 18: Coalescer

HYDROCARBON LIQUIDCONTAINING TINY

DROPLETS OF FREE WATERHYDROCARBON LIQUID

FREE WATER

FIBRE-GLASS ELEMENTS

THE FIBRE-GLASS ELEMENTS GATHER AND COALESCE THEDROPLETS OF WATER WHICH COLLECT IN THE BOTTOM OF

THE VESSEL.

NOTE:THE HYDROCARBON LIQUID WILL STILL CONTAIN SOMEWATER OF SOLUBILITY THAT THE COALESCER CANNOTREMOVE


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Figure: 18a: Coalescer with Controls

SURGE DRUM / COALESCERCOALESCERELEMENTS

SEPARATOR

ELEMENTS

TO FLARE SYSTEM

PURGE GAS FROMFUEL SYSTEM

VENTTRAPS

FE / FICFICV

PIC

PICV

GASDOME

LIC

LICV

S/Vs

VENTTRAP

LdIC 'B'

LdICV 'B'

LdIC 'A'

LdICV 'A'

FE / FI

FT

DRAIN SYSTEM

DRAIN HEADER WATER TO DISPOSAL

FROM OTHER DRAIN SYSTEMS

DRY H/C LIQUIDTO FURTHERPROCESSING

FROM SHUT-DOWN

SYSTEM

TO CONTROL

ROOM

WET HYDROCARBON LIQUID


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LOW PRESSURE SEPARATION (Recovery of Naphtha-rich Gases)

After the 1st - Stage (High Pressure - HP) and 2nd - Stage (Medium Pressure - MP) separators

(GOSPS), the liquids, (oil & water) still contain some heavy solution gases rich in Naphthacompounds Propane, Butane & heavier.

The liquids are piped to further separation units to recover this heavy gas.

The first unit is called a 'Degassing Boot' where the liquids are decreased to a Low Pressure (LP)causing most of the gas to be released from the liquid and piped to a compressor station.

The liquids leaving the degassing boot, is finally passed via an Oil Boot into a 'Surge Tank' where thepressure is decreased to just above atmospheric causing most of the last traces of gas to leave theliquid as Very Low Pressure (VLP) gas that is then piped to a small compressor where its pressure isincreased to that of the LP boot gas and added to it.

The total gas stream is then compressed further, cooled and the resulting condensate

(C3 + Naphtha) is separated, metered and put to other processes. The lighter gases in the surge tank,

the oil and water are also separated. (A demulsifying agent is added to the liquids upstream of thedegassing system to speed up the separation of the water from the oil).

The water is then pumped to a de-oiling station and drained away to a disposal pit.

The oil is metered and pumped to storage for distribution.

The following diagrams and picture show such a degassing system.

(Figures: 19 & 20, & photo)


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FOUR STAGES OF SEPARATION

Figure: 19 Degassing System

INLET FROM WELLS(3-PHASE FLOW)

HIGH PRESSURE (HP) GAS MEDIUM PRESSURE (MP) GAS

LOW PRESSURE (LP) GAS

VERY LOW PRESSURE (VLP) GAS

GAS

OIL

WATER

SURGE TANK

1st STAGE SEPARATORS 2nd STAGE SEPARATORS

COMPRESSOR

3-PHASE FLOW

3-PHASE FLOW3-PHASEFLOW

SALT WATER

CRUDE OIL

DEGASSING BOOT


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Figure: 20

SURGE TANK

OILBOOT

DEGASSINGBOOT

S/V

S/V

LP GAS TOCOMPRESSION

VLP GAS TOCOMPRESSION

WATER TO (SWD) SALT WATER DISPOSAL PUMPS

OIL TO BOOSTER PUMPS, METERING & MAIN LINE PUMPS TO STORAGE

VORTEXBREAKER

FLOWSPREADER

3-PHASE FLUIDFLOW FROM 2nd

STAGE GOSPS

PERFORATED PIPE

SURGE (DEGASSING) TANK

DEGASSING BOOT

OILBOOT

VLP GASOUTLETS

MP, 3-PHASE FLUID FROM2nd STAGE GOSPS

LP GASOUTLET


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SECTION III - DEHYDRATION - GENERAL DESCRIPTION

Before starting on the processes used in the treatment of natural gas for the removal of water vapour,

look at the following diagrams that show definitions of 'Absorption' and 'Adsorption'.

ABSORPTION : Uses liquid desiccants to take in gases. These liquids are called 'Absorbents'and are used not only for water removal but also to remove other unwantedgases from the natural gas, such as: -

Hydrogen Sulphide (H2S) and Carbon Dioxide (CO2). These processes use different absorbents to

the Glycol used in dehydration. These processes are discussed in other booklets.

Absorption then is: - 'The ability of some liquids to 'Take in' or 'Absorb' gases'

ADSORPTION : Uses solid desiccants. These are called 'Adsorbents' and are generally in theform of pellets or granules. Adsorption processes are used for the removal ofany unwanted impurities mainly from gases or liquids such as: -

Water Vapour (H2O), Hydrocarbon Compounds and other undesirable substances.

Adsorption then is: - 'The ability of the molecules of some solids, to hold on their surface,molecules of other substances Gases, Liquids or Solids'.

e.g. A cigarette filter will adsorb nicotine and tar; A car oil filter will adsorb solid particles from thecirculating oil; Blotting paper will adsorb ink or other liquid etc.

See Figures: 21 & 22


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Figure: 21

MINERAL WATER SUCH AS 'PEPSI' CONTAINS 'ABSORBED' CO2 UNDERPRESSURE.

'ABSORPTION' IS THE ABILITY OF SOMELIQUIDS TO 'TAKE-IN' OR 'ABSORB' GASES. INNATURAL GAS PROCESSING, 'GLYCOL' ISUSED TO DEHYDRATE NATURAL GAS BYABSORBING THE WATER VAPOUR

WHEN THE BOTTLE CAP IS REMOVED, A 'HISS' ISHEARD AS THE PRESSURE IS RELEASED.

THE ABSORBED GAS 'STRIPS' OUT OF THELIQUID AS BUBBLES AND ESCAPES TO THEATMOSPHERE.

THESE PRINCIPLES OF 'ABSORPTION' AND'STRIPPING' ARE USED IN GAS PROCESSING TOREMOVE WATER AND OTHER IMPURITIES.

EXAMPLE OF ABSORPTION


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Figure: 22

Most produced natural gas contains water. Some of this water is called 'FREE' water, (liquid phase)and may be removed by passing the gas through a separator or scrubber.After scrubbing, the gas will still contain Water Vapour. This is the water we are concerned about inthis discussion.

The term 'DEHYDRATION' is a process of 'WATER REMOVAL' from a substance or the Dryingof asubstance.

The process of water vapour removal from the natural gas stream is carried out by a process of'ABSORPTION' (using a LIQUID desiccant), or 'ADSORPTION' (using a SOLID desiccant).

In many systems we use the 'Absorption' processes - with a liquid desiccant called 'GLYCOL'.(Generally Tri-Ethylene Glycol (TEG). The process is carried out in towers called 'ABSORBERS' or'CONTACTORS'.

EXAMPLE OF ADSORPTION

CLEAN PRODUCT OUTLET

MOLECULES OFSOLID ADSORBENT MOLECULES OFIMPURITIES

ADSORBENTBEDS

REGENERATION MEDIUM INLET

REGENERATION MEDIUM OUTLET

CONTAMINATED PRODUCT INLET

SUPPORT GRIDS


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In some processes, the water vapour is removed from natural gas by 'Adsorption' using a soliddesiccant called 'Activated Alumina' (Aluminium Oxide), or 'Molecular Sieve' in a 'Drying' process.

Other processes using the Adsorbent principle are: - Instrument air systems generally use 'Silica Gel'

adsorbent; Activated Charcoal is used to remove hydrocarbons and other impurities from a processstream etc.

GENERAL DEHYDRATION OF NATURAL GAS

All of the medium, low and very low pressure gases from the gosps and degassing areas arecompressed to the same pressure and added to, the high pressure, first stage gosp gas.

The wet HP gas then enters the absorber tower bottom and flows upwards through contactingdevices (Raschig rings .. etc, or Bubble-caps). The glycol (called LEAN glycol), enters the tower topand flows down across the contacting devices which give intimate contact between the rising gas anddown-flowing glycol .

Dry gas leaves the top of the tower and goes for further processing while the wet glycol, (now calledRICH glycol), leaves the tower bottom and passes to the glycol 'REGENERATOR' or'RECONCENTRATOR' where, by DISTILLATION, the water is vaporised out and passed to theatmosphere as steam.

The rich glycol, is then re-circulated around the dehydration unit.

(See Figures: 23 & 24)


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Figure: 23 - Operation of a Bubble - Cap Tower

DEMISTERS

LEANGLYCOL

WET GAS INLET

RICH GLYCOL TOREGENERATION

GAS CANNOT PASS UP THEDOWNCOMERS DUE TO THE

LIQUID SEAL FORMED BYTHE TRAY BELOW.

RISING WET GASFALLINGGLYCOL

DRY GAS TO COMPRESSION

RISING WET GASFALLINGGLYCOL

RISING DRY GAS


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Figure: 24 - Operation of Bubble-caps

The up-flowing gas has to pass through the RISER and into the BUBBLE CAPS. The cap turns the

gas flow through 180 forcing it into the liquid on the tray. The gas bubbles through the glycol andgives up water vapour to the liquid and, after the top tray, the gas passes through a demister screenthat coalesces glycol mist into droplets which fall back down the tower.

The trays are fitted with 'DOWNCOMERS', (Weirs), that maintain a liquid level on the tray and carrythe glycol down to the tray below and so on down the tower. the down flowing glycol becomes'Richer' (absorbs more water) as it flows across each tray to the bottom of the tower.

The rich absorbent is then piped to the REGENERATION unit.

The dry gas leaving the tower top, goes to a knock-out drum to separate entrained glycol should anybe carried over with the gas. This glycol, if any, is returned to the glycol system.

See Figure: 25

WEIRTOWER

WALLS

DOWNCOMER

GLYCOL

GAS

RISER

TRAY

TRAYS

GAS

BUBBLE CAP


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Figure: 25 - Simplified Dehydration Unit

The presence of water vapour in natural gas can lead to many problems.The dehydration of natural gas is therefore carried out for the following reasons: -

- Water vapour reduces the ability of gas to flow in the flowlines and process systems.

- Water vapour causes corrosion in lines and equipment.

- At low temperature, water vapour & hydrocarbons form hydrates - complicatedmolecules of hydrocarbon liquid and water, causing blockage of lines and equipment.

Natural gas may contain from 10 to 300 pounds of water vapour per million cubic feet of gasproduced - (10 to 300 lb. water/mmcf), depending on the temperature and pressure of the natural gas;the warmer the gas, the more water vapour it will contain.

Tri-Ethylene Glycol (TEG) dehydration systems are the most common means used for the process.When lean TEG is brought into contact with wet natural gas, it absorbs the water vapour from the gasstream.

WET FEEDGAS

FREE WATER

K.O. DRUM

ABSORBER(CONTACTOR)

TOWER

FREE WATERRICH

GLYCOL

LEAN GLYCOL

GLYCOL DRUM

STILLCOLUMN

REBOILER

SEMI-LEAN GLYCOL

VAPOUR

WATER VAPOUR

DRY GAS

ABSORPTION SECTION GLYCOL REGENERATION SECTION


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The picture below shows two absorber towers using Tri-ethylene Glycol as absorbent for thedehydration of Natural Gas.

The towers each have sixteen bubble-cap trays as contacting devices to give intimate contact between

the rising gas and down-flowing glycol.

Absorber Towers

The pictures on the next page view a Glycol Regeneration Unit from each side: -


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Flue Stack

Still Column

Gas FiredReboiler

Water Vapour to Atmosphere

Gl col ReceiverReboiler FuelControl Area

Glycol

Filters

Glycol FlashTank & Level

Control

Glycol Pumps(Centrifugal)


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PRINCIPLES AND OPERATION OF GLYCOL DEHYDRATION UNIT

DESCRIPTION OF PROCESS AND EQUIPMENT

In the contactor, the up-flowing gas gives up water vapour to the glycol flowing down from the toptray. At the tower top, the dry gas passes through mist extractor elements and then leaves thecontactor top to go on to other processes.

The mist extractor coalesces fine particles of liquid into large droplets which fall back into the glycolpassing down the tower. In this way, glycol carry-over with the gas stream is minimised. SeeFigure: 26.

Referring to Figure: 48, the wet natural gas enters the bottom of the glycol contactor tower and risesthrough the column where it is brought into contact with the lean glycol flowing downwards across

bubble cap trays.

Figure: 26 - Demister Pad Operation

TOWER WALLS MAGNIFIED VIEW

WIRE MESH PADS

DEMISTER SCREENS (OR PADS) PLACED AT THE TOP, INSIDE A TOWER ORSEPARATOR; CONSIST OF WOVEN WIRE MESH THAT PRESENTS A LARGESURFACE AREA TO THE VAPOUR. THIS ALLOWS FINE DROPLETS AND MISTTO COALESCE AND FALL BACK INTO THE TOWER BOTTOM LIQUID.

EXAMPLE OF WIRE MESH DEMISTERS


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The absorption of water vapour during the process, gradually dilutes (weakens) the glycol. The rich(dilute) solution collects in the bottom of the glycol contactor tower from where it is discharged to theglycol regeneration unit by way of a level control system.

At the regeneration unit, the wet glycol flows first to the glycol flash tank where a pressure drop takesplace causing the dissolved gases to leave the glycol as it passes into the flash tank. (This is similar toopening a bottle of Pepsi for example. As the cap is removed, the gas bubbles out of the liquid).

Flash tank pressure is controlled by a PCV in the gas line. (The released gas may be piped to a flareor fuel system or may be passed into the still column).The rich glycol leaves the bottom of the flash tank under level control and passes through a 'Refluxcoil' placed in the top of the still column. (This will be explained later).

After the reflux coil, the glycol is filtered and then passed through a double-pipe heat exchanger to beheated by the regenerated 'lean' glycol leaving the unit reboiler. (This in turn, cools the regenerated(lean) glycol).

The rich glycol now enters the still column at the top tray (below the reflux coil), and flows downacross the bubble-cap trays.

THE REFLUX COIL

The cool, rich glycol as it passes through the reflux coil, picks up heat from the hot, rising gasespassing up the tower from the reboiler. These hot vapours consist of water vapour (steam), entrainedgases and glycol vapour.

The exchange of heat between the liquid in the reflux coil and the rising hot vapours causes the glycolvapour to condense and drop back down the still column.

Some water vapour will also condense but, as it drops back, it is re-vaporised on the top trays of thecolumn. These liquids dropping down from the reflux coil form the internal reflux in the tower thuscontrolling the tower top temperature and therefore the final separation process. Above the refluxcoil, the uncondensed vapour consisting of water vapour and entrained gases pass from the tower topto atmospheric vent stack.

Improper operation of the still column - excess vapour flow, fouling of the reflux coil, low flow rate ofrich glycol through the coil .. etc, will result in glycol vapour remaining uncondensed and escaping to

atmosphere causing glycol losses.

As the glycol flows down the tower across the contacting devices, the absorbed water is stripped outby hot rising vapours from the reboiler.

The glycol, as it collects in the still column bottom section, is now partially regenerated and is referredto as 'Semi-lean' glycol. It is then passed into the reboiler for final water removal.


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Generally, the reboiler is of the 'Fire-tube' type and contains a 'weir' which ensures that the fire tube iscompletely immersed in glycol.

(In systems that have separate reboiler and still column, the weir also maintains the level in the still

column bottom).

In the reboiler, the glycol flows over the weir and enters a stripping section containing Raschig ringsor other contacting devices.

(Extra stripping action may be provided by an injection of dry stripping gas into the reboiler strippingsection).

On leaving the reboiler, the lean glycol passes through the glycol/glycol exchanger into the glycolaccumulator (or storage drum) from where the circulation pumps take suction and discharge theglycol back to the contactor via the glycol cooler, to complete the circuit.

(In some small field units, the still column may be a packed type and is usually an integral part of thereboiler).

(See Figures: 27 & 28).


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Figure: 27 - Complete Glycol Unit - Absorption & Regeneration

DRY GAS TO COMPRESSION

WATER VAPOUR TO VENT STACK

ABSORBER

TOWER

STILLCOLUMN

REFLUX COIL

REBOILER

FLUE GASES

FUEL

STRIPPING GAS

PIC

FIC

SDV

TRAYTOWER TRAY

TOWER

PRESSURISINGGASTOWER

BYPASS

PCV

BLANKET

GAS

VENT

FROM FUEL SYSTEM

GLYCOL / GLYCOL EXCHANGER

GLYCOL

MAKE-

UP

GLYCOL RECEIVER

FLASH GAS

TO FLARE

FLASH

TANK

LIC

DRAIN

RICHGLYCOL

VAPOUR

WET FEED GAS

LEAN GLYCOL PUMPSFIC

RECYCLE

LIC

LEAN GLYCOL COOLER

PUMP-OUTTO

STORAGE

DRAINS

FILTER

PIC


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Figure: 28 - Package type Glycol Unit as used in Field Locations

L.G.

REFLUXCOIL

STACKSTILL COLUMN

(PACKED TYPE)

TIC

SDV

TICV

FICV

FIC

WATER VAPOUR & WASTE GASES

ATMOSPHERICVENT STACK

BLANKET GAS

PCV

FROM FUEL SYSTEM

FUEL

GLYCOL / GLYCOL EXCHANGER

STRIPPING GAS

GLYCOLMAKE-UP

LEAN GLYCOL

ACCUMULATOR

'TRIPLEX' PISTON PUMPS

FILTER

FROMABSORBER

TO ABSORBER

DRAIN

FIRE-TUBE REBOILER


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Figure: 29. Shows the 'Double-pipe, Glycol/glycol exchanger, in more detail.

Figure: 29 - Double-pipe Glycol/Glycol Exchanger

DOUBLE-PIPE HEAT EXCHANGER

TUBE-SIDEHOT FLUID

OUTLET

TUBE-SIDECOOL FLUID

INLET

TUBE-SIDEBYPASS

SHELLHOT FLUID INLET

SHELL BYPASS

SHELLCOOL FLUID OUTLET


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Figure: 30 - Types of Packing Used in Some Still Columns

PACKING BEDS ARE USED TO BRING VAPOUR AND LIQUID INTOINTIMATE CONTACT WITHIN THE TOWER. THEY PROVIDE A LARGE

SURFACE AREA FOR THIS PURPOSE.THE EXAMPLE BELOW SHOWS A BED OF CERAMIC 'RASCHIG' RINGS.OTHER MATERIALS MAY BE USED e.g. STAINLESS STEEL 'PALLRINGS', BROKEN TILE, CERAMIC SADDLES .. ETC.

TYPES OF RASCHIG RING

SUPPORT GRID


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ALTERNATIVE DEHYDRATION PROCESS

PRINCIPLES OF OPERATION

This dehydration process differs from other gas plants in two ways :

1. The glycol used to remove water from the wet gas is MONO-ETHYLENE glycol (MEG)instead of TRI-ETHYLENE glycol (TEG) which is used in most other fields. (See Table ofComparison)

MEG TEG

Formula HO(C2H4O)H HO(C2H4O)3H

Boiling Point (F) 387 549Specific Gravity 1.1 1.1

Flash Point (F) 240 330

2. The lean glycol (MEG) is injected into the wet gas via various points in the system - (i.e. thereis no contactor or absorption tower.

The injection of glycol will prevent the freezing of the water in the gas when a refrigerant (usually

propane) is used to cool the gas to below 0 F for glycol recovery. The rich glycol is collected,

separated from gas condensate in a two section separator and then sent to a glycol regenerationsystem similar to the systems used in other field plants.

It is important to keep the Reflux Coil in the Still column at a temperature sufficient to condense theMEG and allow only water vapour to pass to the vent stack to atmosphere.

The lean glycol (after regeneration) is returned from the reboiler to the injection points.


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Figure: 31 - Glycol injection system and Propane Refrigeration Unit

MAIN OPERATING VARIABLES AND LIMITS

In order to understand the operating mechanism of the glycol dehydration process, it is necessary toconsider and understand the effect of the following four major variables: -

1. - Temperature2. - Pressure

3. - Glycol flow-rate4. - Glycol concentration

REFRIGERANT CONDENSER

PROPANE SURGE DRUM

S/V

PIC

PIC

FIC

LIC

LIC

FIC

O/H's CHILLER INLET GAS CHILLER

GLYCOLINJ'n

EXPANSION VALVE

WARM GASINLET

COOL GAS TOFEED GAS

EXCHANGERS

EXPANSION VALVE

FRACT'n O/HGAS

PROPANEREFRIGERANTCOMPRESSOR

LIQUID REFRIGERANT

VAPOUR REFRIGERANT

VAPOUR

HOT GAS BYPASS

TO SEPARATOR


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1. TEMPERATURE

Temperature of the incoming wet natural gas to the contactor is very important, and is the key factor

affecting the potential use of a glycol dehydrator.

This can be seen clearly by looking at the following points :

- The higher the gas temperature, the more water it will contain in vapour form.

- If the temperature of the wet natural gas is around 140F or above, the natural gas does notwant to give up the water vapour to the glycol.On the other hand, if the natural gas temperature is 40F or below, the glycol becomesviscous and does not want to pick-up the water vapour.Therefore, dehydration will take place at temperatures between 50 to 130F.The best results will be obtained between 80 and 110F .

- The temperature of the lean glycol entering the top tray of the contactor tower should be 10 to15 F above the temperature of the gas to be treated. If the glycol temperature is too muchhigher than the gas temperature, the glycol will tend to foam and be carried out of thecontactor tower with the gas.

Conversely, if the glycol temperature is much lower than the gas temperature, liquid hydrocarbons(condensate) will tend to form and fall to the bottom of the contactor tower causing problems in theglycol regeneration system.

2. PRESSURE

At constant temperature, the lower the pressure, the higher the water content of the inlet gas. Otherthan affecting the water content of the inlet gas stream, pressure has very little effect on the mechanicsof glycol dehydration.

3. GLYCOL CIRCULATION FLOW-RATE

Determining the proper glycol circulation rate is not an easy task due to several limitations and

considerations involved. There are many factors that must be considered but, for simplicity, over anormal pressure range up to 1200 psi, about 3 to 5 gallons of glycol must be circulated for everypound of water removed at a 55 F dew point depression.This quantity of glycol is based on equilibrium conditions, plant design, glycol concentration andother factors, and is calculated by the Plant Chemists.


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4. GLYCOL CONCENTRATION

Since the main objective of natural gas dehydration is maximum dew point depression, relatively

high glycol concentrations are used. The usual practice is to introduce, at the top of the glycolcontactor tower, a solution of regenerated glycol with a concentration ranging from 97 to 99 %, and toremove the solution from the base of the contactor tower at a glycol concentration of 80 to 90 %.

In general, high glycol concentrations will give larger dew point depression (the larger the better), ifthe glycol circulation flow-rate is proportional to the water content of the feed gas.

GLYCOL REGENERATION PROCESS AND EQUIPMENT

THE GLYCOL REBOILER

The glycol regeneration process is very important to maintain the correct concentration of the leanglycol. Refer to Figures: 50 & 52 for the equipment used in the Glycol Regeneration Process.

The glycol reboiler is the main piece of equipment that plays this role in the regeneration process.The reboiler supplies heat to separate the glycol and water by a simple distillation process.

The system consists of a ' U ' shaped, combustion chamber with gas burners, set into the shell of thereboiler and includes an outlet stack for the waste combustion gases.

The shell also contains a ' Weir ' that maintains the level of glycol above the fire-tube in order toprevent overheating of the tube and subsequent damage and/or glycol decomposition by excess heat.

(See Figure: 32)


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Figure: 32 - Fire-tube Reboiler

The temperature of the reboiler should be in the range of 375 to 390

F.This temperature will usually give good distillation of the rich glycol and evaporate all water out of it.

The glycol should never be heated above 400 F as it begins to decompose above that temperature.

Note: When making adjustments to reboiler temperature, never increase the temperature setting bymore than five degrees at a time.

Too great an increase will cause the control system to open the fuel gas valve too wide, giving a largeburner flame which in turn will cause flame impingement on the inside of the fire-tube.This will lead to ' Hot-spots ' and cause damage to the fire-tube and breakdown of the glycol into

corrosive organic acids.

If coke , salts or tar deposits form on the fire tube, the heat transfer into the glycol is reduced, thecontrol system will increase the fuel to maintain the glycol temperature and tube failure can result.Localised overheating, especially where salt deposits accumulate, will decompose the glycol.

VAPOUR

OUTLET

LIQUID LEVEL

STACK

WEIR

PRODUCTSECTION

FIRE-TUBE

IN THIS SECTION, THE WEIRMAINTAINS A LIQUID LEVELABOVE THE FIRE-TUBE TOPREVENT OVERHEATING CONTROLLED

FUEL SUPPLY

FEED

STRIPPING GAS

LEAN GLYCOL

DISTRIBUTOR


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Salt deposits can be detected by shutting off the burner on the glycol reboiler system at night andlooking down the fire-box. A bright red glow will be visible at the hot spots on the fire tube wallswhere salt deposits have collected. An analysis of the glycol will determine the degree of thecontamination.

It is highly recommended that, during a plant start-up, make sure the reboiler is up to the desiredoperating temperature before flowing gas through the contactor .

Some fires have been caused by leaks in the gas lines near the fire-box.The best precaution is to have valves and regulators in the gas line at a suitable distance from the fire-box.

Another very effective measure is the addition of a flame arrestor around the fire-box. If the flamearrestor is properly designed, even severe gas leaks in the immediate vicinity of the fire-box will notignite.

OPERATING PROBLEMS AND GLYCOL CARE

Most operating and technical problems usually occur when the circulating glycol solution gets dirty.In order to get a long, trouble-free life with the glycol system, it's necessary and very important torecognise these problems and know how to prevent them.

Some of the major problems are :-

1. GLYCOL LOSS

2. FOAMING3. THERMAL DECOMPOSITION OF GLYCOL4. DEW POINT CONTROL5. GLYCOL pH CONTROL6. SALT CONTAMINATION7. GLYCOL OXIDATION8. SLUDGE FORMATION


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1. GLYCOL LOSS

The physical loss of glycol is probably the most important operating problem in the dehydrationsystem. Most dehydration units are designed for a loss of less than 0.10 gallons of glycol per

million cubic feet of natural gas treated. However, if the system is not operated properly, the lossmight be much higher than this.

The glycol contactor (the absorber) and glycol regenerator are the most common places in thedehydration system where about 90% of glycol loss occurs. High gas velocity through the glycolcontactor will cause carryover of glycol into the pipeline and a poor mist eliminator (mist extractor) inthe top of the glycol contactor will pass some glycol even at normal gas velocity .

The glycol losses occurring in the glycol regenerator are usually caused by excessive reboilertemperature which causes vaporisation or thermal decomposition of glycol (TEG). Also, excessive toptemperature in the still column allows vaporised glycol to escape from the still column to atmospherewith the water vapour.

2. FOAMING

Foaming of glycol is another problem frequently encountered. It can increase glycol loss and reducethe plant capacity. Entrained glycol will carry over from the contactor (absorber) with the sales gas.Also, foaming can cause poor contact between the gas and the glycol solution ; therefore , the dryingefficiency is decreased. The best cure for glycol foaming, is the proper care of the glycol solution.The most important measures in the program are, effective gas cleaning ahead of the glycol systemand good filtration of the glycol solution.

De-foaming agents such as Mono-ethanolamine (MEA) are widely used to control the problem.However, it's very important to point out that, the use of these does not solve the basic problem, andits only a temporary measure until the cause of the foaming can be determined and eliminated.

Some factors that can cause foaming are: -

- Low glycol solution concentration to the contactor.- High differential temperature between wet gas inlet and lean glycol inlet to the contactor.- High glycol pH - (Note: Basic glycol solution of pH > 9 tends to foam and emulsify)- Hydrocarbon liquids (condensate)- Finely divided suspended solids

- Salt contamination- Field corrosion inhibitors


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3. THERMAL DECOMPOSITION OF GLYCOL

It has been established that the glycol reboiler temperature is limited by the Tri-ethylene Glycoldecomposition temperature , and glycol vaporisation losses.

Laboratory data indicates that glycol (TEG) is thermally stable up to about 400

F. Excessive heat asa result of one or more of the following conditions will decompose the Tri-Ethylene glycol (TEG) andform corrosive compounds .

- A high reboiler temperature above the glycol decomposition level.

- Localised overheating, caused by deposits of salt or tarry compounds on the reboilerfire tube or by flame impingement on the fire tube

4. DEW POINT CONTROL

Dew Point' is the temperature at which the water vapour first starts to condense to liquid. Inindustry, the dew point is used to indicate the water vapour content in the gas stream. For the dewpoint to have meaning as a descriptive term , the pressure at which it is determined must be stated .

When the dew point depression of the treated gas is too low, there can be several causes such as;Low glycol circulation rate; Low lean glycol concentration - i.e poor regeneration of the rich glycolsolution; Foaming (leads to poor contact between the wet gas and the lean glycol solution); Blockedor dirty contacting devices in the absorber tower; High gas velocity in the contactor .... etc.

- Check the glycol circulation rate.

- Check the glycol reboiler temperature and make sure its on the right setting. Iftemperature setting is normal , verify the reboiler temperature with a test thermometerand make sure that the temperature control system is working properly.

As a conclusion, the dew point depression indicates the extent to which the moisture content of a gasis lowered. For example, a 50 dew point depression below a saturation temperature of 80F at 600psia, would indicate that the natural gas, after dehydration, would have to be cooled, to 30 F beforeany condensation of water vapour would occur. From the water vapour content curves, it is seenthat the concentration of water vapour would be decreased from 51.00 lb / mmcf to 9.4 lb / mmcf,representing the removal of 41.6 lb / mmcf or 5 gallons of water per one million cubic feet of gas.

(The greater the dew point depression, the more water vapour removed).


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5. GLYCOL pH CONTROL

The pH of a glycol solution is the measure of its acidity or alkalinity, and is measured on a scale of 0 -

14. A pH of less than 7 is an acid solution , 7 is neutral and, greater than 7 is an alkaline solution.

PH SCALE

0 MORE ACIDIC 7 MORE ALKALINE 14NEUTRAL

The corrosion rate of equipment increases rapidly with a decrease in the glycol pH. The formation oforganic acids, resulting from the oxidation of glycol, thermal decomposition products or acid gasespicked up from the gas stream, are the most troublesome corrosive compounds. Therefore, the glycolpH should be checked periodically and kept on the basic side by neutralising the acidic compounds

with borax, Ethanol-amines or other suitable alkaline chemicals to maintain the pH at 7.5 to 8.0. Aglycol solution that is too alkaline - i.e. pH greater than 9.00, tends to foam and emulsify .

6. SALT CONTAMINATION

Salt deposits accelerate equipment corrosion, reduce heat transfer in the glycol reboiler and changethe specific gravity readings when a hydrometer is used to determine glycol concentration. Thesetroublesome compounds cannot be removed by normal regeneration processes.

Salts should be prevented by the use of effective filters or an efficient scrubber.

7. GLYCOL OXIDATION

Oxygen can enter the glycol system via the vapour space of an un-blanketed storage tank or throughthe glycol make-up pump packing glands ... etc.The glycol will oxidise readily in the presence of oxygen (air) and form corrosive organic acids

Precautions should be taken to prevent glycol oxidation. It is highly recommended, that process

vessels that can draw in air as the liquid level is lowered, should contain a gas blanket to keep oxygen(air) out of the system.Oxidation inhibitors, such as Hydrazine can be used to prevent the formation of corrosive, organicacids.


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8. SLUDGE FORMATION

Accumulation of solid particles and tarry hydrocarbons very often forms in the glycol solution. This

sludge is suspended in the circulating glycol and, over a period of time, the accumulation becomeslarge enough to settle out.

This action results in the formation of a black, sticky and abrasive gum which can cause erosion of theequipment. It usually occurs when the glycol pH is low and becomes very hard and brittle whendeposited on the absorber trays, still column parts and other areas in the circulating system.Good, effective filtration will prevent the build-up of sludge in the glycol system.

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