OPERATION BASIC APPLIED COURSE

PRINCIPLES OF HYDROCARBON PROCESSING

Prepared by: Fathi CHAKROUN

INDEX

1 Introduction ............................................................................................................. 4

2 Gas/Condensate/Water Separation ....................................................................... 6 2.1 General .............................................................................................................. 6 2.2 Principles of Separation ..................................................................................... 6 2.3 Primary Separation ............................................................................................. 7 2.4 Coalescence ...................................................................................................... 7 2.5 Secondary Separation ........................................................................................ 9 2.5.1 General ........................................................................................................ 9 2.5.2 Mist Extraction ............................................................................................. 9 2.5.3 Dissolved Gas Separation ........................................................................... 9

3 Separator Construction ........................................................................................ 12 3.1 Types of Separator ........................................................................................... 12 3.1.1 General ...................................................................................................... 12 3.1.2 Two-phase Separators ............................................................................... 12 3.1.3 Three-phase Separators ............................................................................ 12 3.1.4 Vertical Separators .................................................................................... 13 3.2 Separator Internal Devices ............................................................................... 13 3.2.1 General ...................................................................................................... 13 3.2.2 Deflector Plates .......................................................................................... 17 3.2.3 Weirs .......................................................................................................... 17 3.2.4 Centrifugal Devices .................................................................................... 17 3.2.5 Demister Pads ........................................................................................... 17 3.2.6 Coalescing Plates ...................................................................................... 20 3.2.7 Vortex Breakers ......................................................................................... 20 3.2.8 Horizontal Baffles ....................................................................................... 20

4 Separator Controls ............................................................................................... 22 4.1 General ............................................................................................................ 22 4.2 Pressure Control .............................................................................................. 22 4.3 Three-Phase Separator Level Control .............................................................. 22

5 Condensate Treatment ......................................................................................... 24 5.1 Operation ......................................................................................................... 24 5.2 Stabilizer Construction ..................................................................................... 24 5.2.1 General ...................................................................................................... 24 5.2.2 Tower Trays ............................................................................................... 25 5.2.3 Tower Packing ........................................................................................... 25

6 Gas Dehydration ................................................................................................... 27 6.1 Introduction ...................................................................................................... 27 6.2 Dehydration by Absorption (Glycol Dehydration) ............................................. 27 6.2.1 General ...................................................................................................... 27 6.2.2 Process Flow Overview .............................................................................. 28 6.2.3 Glycol Contactor ........................................................................................ 29 6.2.4 Gas/Glycol Heat Exchanger ....................................................................... 33 6.2.5 Glycol Skimmer/Flash Tank ....................................................................... 33 6.2.6 Stripper Column and Reboiler .................................................................... 36

6.2.7 Surge Tank ................................................................................................ 36 6.2.8 Lean/Rich Glycol Heat Exchanger ............................................................. 36 6.2.9 Glycol Filters .............................................................................................. 37 6.3 Dehydration by Adsorption (Molecular Sieve Dehydration) .............................. 37 6.3.1 General ...................................................................................................... 37 6.3.2 Process Flow Overview .............................................................................. 41 6.3.3 Feed Gas Chiller ........................................................................................ 42 6.3.4 Feed Dryer Separator ................................................................................ 42 6.3.5 Molecular Sieve Beds ................................................................................ 42 6.3.6 Regeneration Gas Heater .......................................................................... 42 6.3.7 Regeneration Gas Coolers ........................................................................ 42 6.3.8 Regeneration Gas Knock-out Drum ........................................................... 43

7 Pipelines ................................................................................................................ 45 7.1 History .............................................................................................................. 45 7.2 Types of Pipeline .............................................................................................. 45 7.3 Pipeline Materials ............................................................................................. 46 7.4 Pipeline Protection ........................................................................................... 46 7.5 Pipeline Operation ............................................................................................ 47

8 Pipeline Pigs ......................................................................................................... 48 8.1 General ............................................................................................................ 48 8.2 Pig Launching and Receiving ........................................................................... 48

9 Liquid Product Storage ........................................................................................ 52 9.1 General ............................................................................................................ 52 9.2 Cone Roof Tanks ............................................................................................. 52 9.3 Floating Roof Tanks ......................................................................................... 52 9.4 Tank Construction ............................................................................................ 53

1 Introduction

Refer to Figure 1.1. Due to the impurities present in natural gas and hydrocarbon condensate when initially recovered from the reservoir, they are not immediately saleable products. The gas and condensate require separation then further treatment to remove or convert the impurities before they can be sold as product. The type of treatment depends on the type of impurities present and the final use to which the products are to be put. Typical impurities present in natural gas and condensate include:

hydrogen sulphide (H2S)

carbon dioxide (CO2)

water

nitrogen. H2S and CO2 when mixed with water form weak acids and are thus termed 'acid gases'. These acid gases are highly corrosive to pipelines and equipment and need to be removed from the gas stream. In addition, H2S has the potential to cause hydrogen embrittlement of steel and is highly toxic even at low concentrations. H2S and CO2 can be removed by absorption, the specific absorption process being determined by the amount of unwanted constituents present in the gas. Natural gas and condensate recovered from the reservoir are often saturated with water and the absorption processes used for acid gas removal can also cause the gas to be water saturated. Corrosion of pipelines and equipment is accelerated in the presence of water and when water is present in a gas stream at certain conditions of temperature and pressure, hydrates can form. Hydrates are a loosely linked crystalline compound of water and hydrocarbons. The crystals cause plugging of flowlines, valves, exchangers and instrument lines and can be extremely troublesome in plant operation. Since hydrates only form in the presence of water, removing the water from the gas can prevent their formation. Dehydration processes can reduce the water content of the gas (measured as dewpoint) and these generally involve the use of a solid or liquid desiccant. Having essentially no calorific value, nitrogen lowers the heating value of the gas, reducing the sales value. Where there exists a high proportion of nitrogen in the gas stream it can be removed using permeable membranes or low temperature separation processes. Both techniques are costly and complex and are not discussed in this module. The hydrocarbon condensate from the reservoir may contain high proportions of methane and ethane, depending on the reservoir pressure. To achieve the correct specification for shipping or transfer of the condensate by pipeline, ethane and methane must be removed. This stabilization can be achieved by a series of 'flashes' where a series of pressure drops allows light ends to flash out of solution in the condensate. Alternatively, a distillation system can be used to stabilize condensate.

This module examines:

three-phase separation (gas/condensate/water)

condensate stabilization

gas dehydration

pipelines

pigging operations

liquid storage.

Figure 1.1 - Wellstream Components

2 Gas/Condensate/Water Separation

2.1 General

A field production separator is a pressure vessel in which a mixture of well fluids that are not soluble in one another are separated from one another. Well stream fluids include gas, condensable and non-condensable vapours, water vapour, hydrocarbon condensate, water and solids. When well fluids reach the surface where the pressure is lower than in the reservoir, the capacity of the liquid to hold gas in solution is reduced and gas separates out of the condensate. Additionally, the temperature at the surface is lower than the reservoir temperature and therefore some wellstream vapours condense and combine with the liquid. Production separators are used to separate and segregate gas from liquid and lighter liquid from heavier liquid, e.g. condensate from water. The main functions of a field production separator are:

to effect a primary separation of gas from liquid

to continue this process by removing entrained liquid from the gas. Additionally, the separator must have the following characteristics:

allows sufficient time for gas to be released from the condensate

allows sufficient time for the separation of condensate from water

provides controls to prevent gas escaping with the liquids

discharges the separated components in such a way as to render it impossible for them to be remixed.

2.2 Principles of Separation

Four physical factors are necessary for separators to function:

gravity

fluid insolubility

difference in fluid densities

reduced pressures. Separation depends upon the effect of gravity to separate the fluids. For efficient separation to take place, the fluids must not be soluble in one another. For example, gasoline, diesel oil and crude oil cannot be separated in a separator vessel because they dissolve in each other. A distillation process must separate them. Because a separator depends upon gravity to separate fluids, the ease with which separation takes place depends upon the difference in the weight of the fluids. Gas is very much lighter than condensate, and in a separator these

separate in just a few seconds. However, condensate, which weighs only about two thirds of the weight of the same volume of water, will take between 30 and 60 seconds to separate from water The density of a fluid is the mass of unit volume of a substance expressed in units such as kg/m

3.

2.3 Primary Separation

Refer to Figure 2.1. Because of the difference in density between gas and condensate, approximately 90% of gas/liquid separation takes place instantly. This is known as primary separation or flash separation. However, some liquid remains in the gas in the form of droplets or fine mist and this entrained liquid must be removed before separation is complete. If the mist is not removed from the gas phase in the separator, liquid settles out in the gas outlet flowline, causing operating problems in downstream treating units. An amount of condensate product will also be lost.

2.4 Coalescence

The most difficult function of a field production separator is to extract mist from the gas. Mist consists of liquid droplets suspended in the gas flow (just as water droplets occur in air as fog). Mist will not fall out of the gas unless the droplets are forced together to form larger drops that are heavy enough to fall. The process of combining many droplets into larger drops is known as coalescence. Coalescing devices are installed in separator vessels to perform this function. Examples of coalescing devices include:

demister pads

vane type mist extractors

coalescing plates. The efficiency of mist extraction devices depends largely upon the amount of coalescing surface area available in the separator.

KIO-4-0127.CDR

WELL-STREAMINLET

PRIMARYSEPARATION

SECONDARYSEPARATION

GASOUTLET

LIQUIDOUTLET

LIQUIDSETTLINGSPACE

VAPOURDISENGAGINGSPACE

Figure 2.1 - Gas Separation and Liquid Settling

2.5 Secondary Separation

2.5.1 General

In the field production separator there are two stages of secondary separation: separation of liquid mist from the gas phase (mist extraction) separation of dissolved gas from the liquid phase.

2.5.2 Mist Extraction

Liquid mist separates from the gas phase provided the following conditions are met:

the gas stays in the separator long enough for the mist to dropout

the flow of gas through the separator is slow enough to prevent turbulence (turbulent gas flow inhibits efficient mist extraction).

The difference between gas and liquid density determines the maximum flowrate of gas that allows the mist to separate efficiently. For example, mist separates from gas at 15 kg/cm

2 if the gas is flowing through the separator at less than

1 m/second. This means that the vessel needs to be large enough for the gas to flow from the inlet nozzle to the outlet nozzle at 1 m/second or less. This time factor is known as the gas residence time (the time required for mist extraction from gas). Pressure has an important effect on mist extraction efficiency. Because gas density is lower at lower pressures, the liquid droplets separate faster due to the greater difference in weight between the low-pressure gas and liquid. The gas flowrate can thus be increased if the separator operates at a lower pressure.

2.5.3 Dissolved Gas Separation

Refer to Figure 2.2. Due to the lower operating pressure in the separator, gases dissolved in the condensate phase expand to form bubbles. This bubble formation often results in foam on top of the condensate phase. The pressure at which gas bubbles foam in condensate is called the bubble point pressure. In most field production separators, gas bubbles in the liquid breakout of the condensate phase in about 30 to 60 seconds. The separator, therefore, is designed so that the liquid stays in the vessel for 30 to 60 seconds. This period that the liquid remains inside the vessel is known as the liquid residence time (the time required for gas to bubble out of the liquid).

Liquid residence time can be calculated as follows:

Liquid Residence time = FlowrateInlet

VesselofVolumeLiquid

For example, a field production separator with a liquid volume of 50 m

3 and an

inlet flowrate of 50 m3

/minute has a liquid residence time of 1 minute.

KIO-4-0127.CDR

WELL-STREAMINLET

FLOWRATE50m /MINUTE

3

CONDENSATEVOLUME

50m3

GASOUTLET

LIQUIDOUTLET

RESIDENCETIME 1 MIN

Figure 2.2 - Liquid Residence Time

3 Separator Construction

3.1 Types of Separator

3.1.1 General

Field production separators are classified by the number of fluids, which are separated in the vessel, i.e. two-phase or three-phase. They can be further categorized as vertical or horizontal.

3.1.2 Two-phase Separators

Figure 3.1 shows a horizontal two-phase separator. The wellstream fluids enter at the side or end and are routed through a cyclone separator. This centrifugal device assists in separating the lighter and heavier components in the stream by imparting a circular motion to the fluids. Heavier material drops out and settles in the bottom of the separator. Further separation is effected by mist in the fluid being coalesced in contact with the coalescing plates. The York mesh demister pad removes the final droplets from the lighter (gas) fluid as it leaves the separator. Heavier (liquid) components are removed from the bottom of the separator.

3.1.3 Three-phase Separators

Figure 3.2(A) shows a three-phase separator with a weir. In this type of vessel the wellstream fluids enter at the vessel end. Gas flows out of the top of the vessel under pressure control. The water and liquid hydrocarbon settle out at the left bottom section. The hydrocarbon material, being lighter, floats on top of the water and as the level rises, it overflows the weir into the hydrocarbon compartment from where it leaves the separator under level control. The water phase remains in the left side of the separator and is also disposed of under level control. In this type of separator difficulties can be encountered due to emulsions and foams forming in the separator. These interfere with the efficient operation of the level controllers. Figure 3.2(B) shows an improved design of three-phase separator where level control of the water and hydrocarbon phases are not affected by foaming or emulsion formation. The hydrocarbon phase overflows a weir and enters a

hydrocarbon 'bucket' compartment. From this compartment it leaves the separator under level control. The water phase flows along the bottom into a chamber on the right where it leaves under level control.

3.1.4 Vertical Separators

Refer to Figure 3.3. The vertical separator may be either two-phase or three-phase depending on the type of operation. This type of separator is used where large liquid slugs are expected and where liquid level control is not critical to unit operation. Incoming well fluids meet an inlet deflector plate on entry to the separator. This deflector plate spreads the incoming fluids inside the separator shell and imparts a centrifugal motion to the gas which allows gas and liquid to disengage. The liquid falls to the bottom of the separator while the smaller liquid particles are swept upward to coalesce on the outlet demister pad. A vertical separator occupies less area that the horizontal separator and is easier to clean. The natural upward flow of gas opposes the falling liquid droplets; therefore the vertical separator is larger than a horizontal separator of the same capacity. However, vertical separators have less tendency for revaporization of liquid than horizontal separators.

3.2 Separator Internal Devices

3.2.1 General

Internal devices are used in production separators to:

improve separation efficiency

accelerate the separation process

reduce the size of the vessel. The internal devices used in vertical and horizontal separators are virtually identical. A number of internal devices are commonly used, as described in Sections 3.2.2 to 3.2.8 below.

Figure 3.1 - Two-phase Horizontal Separator

KIO-4-0130.CDR

LC

LC

LC

LC

PC

PC

GASOUTLET

GASOUTLET

CONDENSATEOUTLET

CONDENSATEOUTLET

WATER OUTLET

WATEROUTLET

WELLSTREAMINLET

WEIR

BUCKET

WELLSTREAMINLET

(A) WEIR TYPE

(B) BUCKET TYPE

Figure 3.2 - Three-phase Horizontal Separators

KIO-4-0131.CDR

DEFLECTORPLATE

DEMISTERPAD

GASOUTLET

WELLSTREAMINLET

BLOWDOWNINLET

PRESSURIZEDWATER INLET

SANDOUTLET

SANDCONE

LIQUIDOUTLET

WATER OUTLET

VORTEXBREAKER

HYDROCARBONLIQUID

OUTLET

DEFLECTORPLATE

DEMISTERPAD

WEIR

GASOUTLET

WELLSTREAMINLET

VERTICAL 3-PHASEPRODUCTIONSEPARATOR

VERTICAL 2-PHASEPRODUCTION

SEPARATOR WITHSAND REMOVAL

Figure 3.3 - Vertical Separators

3.2.2 Deflector Plates

Refer to Figure 3.4. These are fitted in front of the inlet to the separator and can be flat or dish-shaped. They absorb the impact of the incoming wellstream and create a rapid separation of gas and liquids. They also slow the flowrate of fluids through the vessel.

3.2.3 Weirs

Refer to Figure 3.5. This is a wall installed inside the vessel. The weir increases the liquid residence time. Condensate overflows the weir to enter the hydrocarbon chamber. Weirs are also used to form a bucket arrangement inside the separator.

3.2.4 Centrifugal Devices

Refer to Figure 3.6. Also known as cyclone separators, these are an assembly of concentric cylinders used at the wellstream inlet for gas-liquid separation. The device imparts a swirling motion to the incoming well fluids. Centrifugal force causes the heavier liquids to travel outwards to contact the outer cylinder wall and fall to the bottom. The gas adheres to the centre cylinder wall, travels downwards, and turns to enter and flow up the centre annulus to exit the device at the top. This is a highly efficient method of separation.

3.2.5 Demister Pads

Refer to Figure 3.7. Demister pads are coalescing devices used to extract the mist from gas. The pad is made from knitted wire forming a close mesh usually 10 to 20 cm thick. The mesh pad is contained in a strong support frame to prevent it from being damaged by sudden surges of gas.

Figure 3.4 - Deflector Plate

Figure 3.5 - Weir/Bucket Arrangement

Figure 3.6 - Centrifugal Device (Cyclone Separator)

Figure 3.7 - Demister Pad

3.2.6 Coalescing Plates

Refer to Figure 3.8. These are used to remove liquid from gas and assist in the separation of water from oil in oil field emulsions. The emulsion is forced to follow a path that constantly changes direction; this causes the water droplets in the emulsion to coalesce and fall to the bottom of the separator.

3.2.7 Vortex Breakers

Refer to Figure 3.9. Vortex breakers are fitted above the liquid outlet nozzles in all separators to prevent a vortex from forming, which would otherwise allow gas to flow out of the liquid lines.

3.2.8 Horizontal Baffles

Horizontal baffles prevent wave action in the liquid phase.

Figure 3.8 - Coalescing Plates

Figure 3.9 - Vortex Breaker

4 Separator Controls

4.1 General

Refer to Figure 4.1. Oil production separators have two major operating control points: pressure control and level control. Separator temperature is usually fixed by the wellstream inlet temperature.

4.2 Pressure Control

The gas capacity of a separator increases as the operating pressure increases. The separator operating pressure is controlled as high as possible to achieve efficient separation. Increasing the pressure reduces gas volume, and decreases gas flow velocity in the vessel. The operating pressure of a separator is controlled by a backpressure controller, which regulates the flow of gas leaving the vessel.

4.3 Three-Phase Separator Level Control

The term water cut is used to describe the percentage of water to total liquid. A 20% water cut is 20% water and 80% condensate. In the separator shown in Figure 4-1, the level in the liquid settling chamber if fixed by the height of the weir. The volume of oil in the oil chamber is relatively small, and changing the level of oil in this chamber has no effect on the liquid settling volume, or residence time. Liquid residence time is determined by the water level in the settling chamber. If the water level is increased, the water residence time increases but the oil residence time decreases. Liquid carryover in the outlet gas stream of three-phase horizontal separators is not usually a level control problem. Commonly this problem is caused by defective coalescing devices or an abnormally high gas flow.

KIO-4-0139.CDR

LCLC

PCPITI

PSV

TI

GASOUTLET

CONDENSATEOUTLET

WATEROUTLET

WELLSTREAMINLET

WEIR

VENT TOBLOWDOWN

RUPTUREDISC

SETTLING CHAMBER

VAPOUR/GAS SPACE

CONDENSATECHAMBER

DRAIN

Figure 4.1 - Typical Separator Controls

5 Condensate Treatment

5.1 Operation

The hydrocarbon condensate separated from the gas stream in the separation section of the plant requires further treatment to minimize its gas content. This treatment is generally done in a condensate stabilizer system, which removes residual light ends from the condensate, by conventional distillation. In the example shown in Figure 5-1, condensate containing a high proportion of light ends is fed to the condensate stabilizer. In the stabilizer the liquid falls downwards in a process that results in many flashes at progressively higher temperatures. At the stabilizer bottom a proportion of the condensate is removed and passed to a reboiler to provide the necessary bottoms temperature. The stabilized condensate from the bottom of the stabilizer is cooled before being passed to storage or export. The vapours leaving the top of the tower are cooled to condense any intermediate components leaving with the light ends, and the overhead product is routed to a reflux drum. From the reflux drum the condensed intermediate produce is pumped back to the top of the tower where it assists in stripping out intermediate product vapour rising up the tower. The gas evolved in the stabilizer is drawn off the reflux drum, either for re-compression or for use as fuel gas. The reboiler’s heat requirement depends on the amount of cooling done in the overhead condenser. The colder the overhead product leaving the condenser, the purer the liquid in the reflux drum. The hotter the stabilizer bottoms temperature, the greater the proportion of light components will be boiled out of the bottoms liquid and thus the lower the vapour pressure of the bottoms liquid.

5.2 Stabilizer Construction

5.2.1 General

The number of flash stages required determines the number of trays required. The more trays in the tower the more efficient the split of light ends from condensate but this makes the tower taller and more costly.

A typical condensate stabilizer will have approximately 20 trays. These will normally be arranged as 8 trays above the feed point and 12 trays below.

5.2.2 Tower Trays

The flow of gas through each tray is normally controlled by bubble caps, perforations or valves. The least expensive tower trays have perforations but this type of tray provides less effective gas/liquid contact on the tray. Where there is low gas velocity, the more expensive bubble cap trays or valve trays are used. These provide more effective gas/liquid contact and help seal the trays at low gas velocity. Tower dimensions are determined by the manufacturer’s data for the particular tray design selected. The distance between trays is typically between 50 and 75 centimetres depending on specific design and liquid flow rate.

5.2.3 Tower Packing

For smaller diameter towers, packing is often used, as it is less expensive. Packing suffers from the disadvantage of poor performance at low flow rates and can be prone to channelling.

Figure 5.1 - Condensate Stabilisation

6 Gas Dehydration

6.1 Introduction

Where gas is to be transported long distances by pipeline, or where it is to be chilled to very low temperatures, there is a requirement to reduce the water content of the gas. This is to obviate the problems of corrosion within pipelines and the problem of hydrate formation and, in the case of low temperature applications, to prevent water freezing out in pipelines or equipment. In addition, free water, produced by condensation in a pipeline, can give rise to two-phase flow and reduce the capacity of the pipeline. This water removal, known as gas dehydration, can be achieved either by an absorption process where the gas is contacted with a hygroscopic absorption medium such as glycol, or by an adsorption process where water removal is achieved by contact between the gas and a solid dehydration medium such as a molecular sieve.

6.2 Dehydration by Absorption (Glycol Dehydration)

6.2.1 General

The most common field process for gas dehydration to normal pipeline requirements is by dehydration using a liquid desiccant (desiccants are substances, available in either liquid or solid state, having a great affinity for water). A commonly used liquid desiccant is tri-ethylene glycol (TEG). The dehydration process may be regarded as comprising two phases:

Phase One is the absorption process, i.e. the removal of water vapour from the gas by TEG.

Phase Two is the regeneration process, i.e. the reconditioning or reconcentration of the glycol (which absorbed the water from the gas in Phase One) for re-use in the absorption process.

The process is a continuous one with Phases One and Two running concurrently. Absorption takes place in a vessel called a contactor. In this vessel the wet gas and the liquid glycol desiccant flow in opposite directions. The gas flows up and the glycol flows down. The gas exits at the top and the used desiccant (glycol) exits at the bottom to flow into a skimmer/flash tank, which separates any liquid and gaseous hydrocarbons from the used glycol. These two items of plant comprise Phase One, the absorption phase. The used glycol desiccant from

Phase One is referred to as rich glycol (the glycol has been enriched with absorbed water from the gas). The rich glycol flows next to the regenerator system, which comprises Phase Two.

6.2.2 Process Flow Overview

Refer to Figure 6.1. An inlet gas scrubber, either integral in the bottom section of the contactor tower or a separate vessel located upstream of the contactor, is used to remove free liquids from the gas stream. Free liquids (water and hydrocarbon condensate) which have condensed in the pipeline can cause the following operational problems: a) Extra water puts an unnecessary load on the glycol and can overload the

absorber section of the contactor such that the specified outlet gas dewpoint is not achieved.

b) Hydrocarbon liquid causes glycol to foam, thereby reducing the gas handling capacity in the absorber section of the contractor and high glycol losses from the tower top and regeneration system.

After gas scrubbing, the wet gas flows upwards through a series of bubble cap type trays, where the gas is contacted with glycol flowing downwards across the trays. Each tray has many bubble caps fitted to provide efficient dispersion of the gas across the tray and through the glycol liquid level. Bubble caps provide the means of contact, mixing and absorption for the countercurrent flow of gas and liquid glycol. Some water vapour is absorbed from the gas stream by the glycol on each tray. The gas leaving the top tray has most of the water content removed and passes through a mist extractor to remove entrained glycol before leaving the tower. The lean glycol enters the contactor at the top bubble cap tray and flows across the tray to a downcomer, which directs the glycol to the tray below. The glycol flows across this tray to another downcomer; this flow sequence is repeated until the glycol exits from the bottom tray into the bottom section of the contactor. Rich glycol, which accumulates in the bottom of the contactor, contains the water it absorbed from the gas. This rich glycol now flows under pump level control to the regeneration system. The lean glycol entering the top tray must be cooled down to 8

oC to 10

oC higher

than the gas stream to allow more efficient absorption of water vapour. To accomplish this, the lean glycol (at approximately 140

oC on the discharge of the

glycol pump) is heat exchanged with the outlet gas in the gas/glycol heat exchanger. The wet rich glycol from the contactor bottom flows through the reflux coil in the top of the stripper column. The cool rich glycol is used as a heat transfer medium to cool the hot vapours leaving he stripper column. This condenses as much of the glycol from the vapours as possible before releasing the water vapour to the

atmosphere. A manual valve controls the rich glycol reflux flowrate through the coil. For the final regeneration of the rich glycol, the glycol is heated to 240°C to 270°C in the reboiler. After regeneration, the lean glycol is cooled to approximately the temperature of the gas before contacting. To minimize the amount of energy used in the reboiling operation, it is economical to conserve the heat from the hot lean glycol solution by heat transfer with the cold rich glycol solution. This also reduces the solution temperature of the lean glycol to the pump and into the contactor. The lean/rich glycol exchanger decreases the temperature of the lean glycol solution to 140°C. After being pre-heated in the lean/rich glycol exchanger, the rich glycol flows to the stripper column. On entering the stripper the rich glycol flows downward through a packed section where it contacts and mixes with hot vapours rising from the reboiler below. On contact the rich glycol becomes heated and some of the water boils and is released from the solution as water vapour. This water vapour leaves the stripper column from the atmosphere vapour outlet or vent located at the top of the column section. From the stripper the glycol enters the reboiler where further heating to 240

oC to 270

oC takes place to obtain the

required dry lean glycol concentration or purity. The reboiler glycol level is maintained above the top of the heater by a standpipe, and the glycol temperature is controlled by a temperature controller. The hot regenerated lean glycol overflows the reboiler standpipe and enters the integrated surge tank, then flows through the shell side of the lean/rich glycol exchanger to the glycol pump. The glycol pump raises the lean glycol solution pressure slightly above that of the contactor. The lean glycol is pumped through the gas/glycol exchanger where it is cooled against outlet gas, and enters the top tray of the contactor tower.

6.2.3 Glycol Contactor

Refer to Figure 6.2. The contactor is a high-pressure vessel containing a number of bubble cap trays on which the up-flowing gas bubbles through down-flowing glycol solution. The number of trays in the contactor affects the amount of water vapour removed from the gas by the glycol. The untreated wet gas flows into the base section of the vessel and passes up the absorber trayed section. Lean glycol enters above the top tray and flows down the vessel against the rising gas. The lean glycol absorbs water vapour from the gas during this contra-flow. Treated dry gas leaves the contactor at the top nozzle and the wet rich glycol exits at the bottom. The operating conditions of flow, pressure and temperature affect the rate of water absorption and contactor efficiency. Tower operating conditions also affect the amount of hydrocarbons dissolved in the glycol solution. More gas is dissolved in the glycol when the pressure is increased or the temperature decreased. The rich glycol solution flows from the lower section of the contactor under pump level control to the

skimmer/flash tank where any dissolved hydrocarbons are separated from the glycol. A mist extractor section above the top tray removes any glycol entrained in the outlet gas stream. This reduces the losses of glycol solution from the circulation system. The bubble cap trays cause the rising gas to disperse through the glycol and allow the required contact and mixing for absorption to take place. The gas flows through a riser such that the gas diverts from the top of the cap down through the annulus formed between the riser and the cap. The gas then disperses through slots in the bottom of the cap rim and bubbles up through the glycol liquid. The level of glycol is maintained near the top of the caps by weirs on the tray decks. The deeper the glycol level around each cap, the more intimate the glycol/gas contact, and the greater the absorption efficiency. Glycol flows in an alternating flow path from one tray down on to the tray below via a series of weirs and downcomers; this tray arrangement is called single pass. The intimate contact on the trays allows the glycol, with its high hygroscopic ability, to absorb the water vapour from the gas stream. The largest amount of water is removed on the bottom tray, where the gas contains the most water. Progressively the gas contains less water as it moves through each successive tray; therefore, the glycol absorbs less water and is more hygroscopic higher up the tower. On the last few trays, the glycol is at its leanest and only trace amounts of water vapour remain in the gas. These top trays remove the last trace amounts of water in the gas to meet the specified outlet gas dewpoint or water content. Rate of gas and glycol flow is crucial in the contactor. If the gas velocity is too high it may result not only in the gas having too little contact time (exposure) with the glycol, but also cause the bubble caps to lift off. The caps on some contactors are, therefore, tack welded into place on the tray.

Figure 6.1 - Glycol Dehydration, Process Flow

Figure 6.2 - Glycol Contactor Tower

6.2.4 Gas/Glycol Heat Exchanger

Refer to Figure 6.3. The final stage of lean glycol solution, cooling, is accomplished in an exchanger that cools the glycol to a temperature about 3

oC above that of the wet gas

entering the contactor. In this heat exchanger the dry outlet gas leaving the contactor cools the lean glycol flowing from the glycol pump to the contactor. The outlet gas line from the contactor is finned and has a larger diameter pipe welded around it, through which the lean glycol flows.

6.2.5 Glycol Skimmer/Flash Tank

Refer to Figure 6.4. Some gases dissolve in the rich glycol solution in the contactor; liquid hydrocarbon may also be carried out of the bottom of the tower in the rich glycol. Large quantities of liquid hydrocarbon carryover to the downstream regeneration equipment is troublesome and dangerous to unit operations, and can cause:

flooding in the stripper column

foaming in the stripper column and increased glycol losses to atmosphere

excessive flashing in the reboiler

fire hazard on the reboiler firetube due to glycol level disturbance uncovering the firetube surface.

Dissolved gas and liquid hydrocarbon are removed from the rich glycol in the glycol skimmer/flash tank. The skimmer is a separator in which gas, liquid hydrocarbon and glycol are separated from one another. The gas separates from the liquid by flashing and passes out of the top of the vessel to enter the fuel gas system. A pressure control system regulates the flow of gas leaving the skimmer vessel and usually set at 2.5 to 3.5 kg/cm

2.

The separated lighter liquid hydrocarbon overflows into a trough or bucket assembly located across the centre of the vessel and is removed by manual draining. The heavier and denser glycol liquid forms a lower level in the vessel and leaves under level control to enter the charcoal filter.

Figure 6.3 - Gas/Glycol Heat Exchanger

Figure 6.4 - Glycol Skimmer/Flash Tank

6.2.6 Stripper Column and Reboiler

Refer to Figure 6.5. The stripper column removes the water that the glycol has absorbed in the contactor, operating at pressures close to atmospheric. It contains packing material such as stainless steel rings or ceramic saddles. To improve efficiency a reflux coil can be fitted in the top of the unit. Cool rich glycol flows through the coil and condenses some of the glycol vapour flowing around it. This reflux system reduces the amount of glycol lost to atmosphere in the vapour phase. The heat requirement for the stripper system is supplied by the reboiler. This supplies energy to boil water out of the rich glycol solution. A temperature control system maintains the temperature in the region of 240

oC to 270

oC. The water

boiled out of the rich glycol in the stripper flows out of the top vapour vent to atmosphere. An important factor affecting the amount of water removed from the gas by the lean glycol solution is the purity of the solution. Most glycol units operate with a lean glycol purity of 98% to 99.5% by weight. A high purity glycol will remove more water than glycol solution of lower purity. Glycol purity is controlled in the stripper. At the reboiler temperature, glycol purity is approximately 98.5% by weight. A higher purity could be obtained by increasing the reboiler temperature but the higher temperature would result in degradation of the glycol. Sometimes a flow of dry gas, known as stripping gas, is sparged into the reboiler. This has the effect of further reducing the water content of the glycol in the reboiler.

6.2.7 Surge Tank

Refer to Figure 6.6. Glycol is lost in the outlet gas stream from the contactor and also in the water vapour vent from the stripper. Typical glycol losses are about 1 litre/100 m

3 of

gas. The surge tank provides storage for the lean glycol so that there is no requirement to continually make up losses. Surge tanks are generally designed to contain a sufficient supply for one month.

6.2.8 Lean/Rich Glycol Heat Exchanger

Refer to Figure 6.7.

In this exchanger approximately 65% of the heat in the hot lean glycol leaving the stripper column is transferred to the cool lean glycol entering the contactor. The temperature of the lean glycol leaving this exchanger is around 110

oC. Typically

rich glycol will flow through the tubeside of the exchanger and lean glycol through the shell side.

6.2.9 Glycol Filters

Refer to Figures 6.8 and 6.9. Gas entering the contactor may have lime scale, rust, sand, iron sulphide or other solid foreign bodies in it. This material, if allowed to remain in the system, can cause foaming, a condition which adversely affects the efficiency of the glycol absorption process. Solids can also cause mechanical damage to the glycol pumps or plug stripper packing. To remove this material, glycol filters are used. A high-pressure cartridge type filter, known as a sock filter, is used between the contactor and the glycol pump. This removes solids of up to 5 microns in size. The filter element (the sock) is easily removed for cleaning or replacement. The glycol solution is further filtered using a charcoal filter. This filter is located between the skimmer/flash tank and the stripper column. This filter removes hydrocarbons; well treating chemicals and other agents that may promote foaming in the contactor and regeneration systems. The charcoal filter is filled with an activated carbon substance, which removes impurities, by an adsorption process.

6.3 Dehydration by Adsorption (Molecular Sieve Dehydration)

6.3.1 General

Adsorption is the process of removing an unwanted constituent from a fluid stream by contacting the fluid stream with a solid desiccant. In molecular sieve dehydration units, multiple beds are used on a continuous basis in cyclic operation. Such units may employ two or more molecular sieve dryers; typically one will be in service, one on regeneration and one or more on standby.

Figure 6.5 - Glycol Stripper Column

Figure 6.6 - Glycol Reboiler with Integral Surge Tank

Figure 6.7 - Lean/Rich Glycol Heat Exchanger

Figure 6.8 - Glycol Sock Filter

Figure 6.9 - Glycol Charcoal Filter

6.3.2 Process Flow Overview

Refer to Figure 6.10. Feed gas is routed to the gas dehydration unit by way of a chiller where the gas temperature is reduced to 21° to 25

oC in a feed gas chiller. Temperature control

of the chiller is critical at this stage. If the temperature of the gas leaving the chiller is too low, hydrates can form blocking pipework and equipment. If the temperature is too high, not enough liquids will condense in the feed dryer separator and the molecular sieve beds will become overloaded. Chilled fluids are routed to the feed dryer separator where water and liquid hydrocarbon condense out. These are disposed of under level control and the gas is passed forward to the on-line molecular sieve gas dryer. In the molecular sieve gas dryer the gas passes downward over the molecular sieve bed. Water molecules are attracted on to the surface of the molecular sieve and gas molecules are allowed to pass through. At the exit of the gas dryer there is an after-filter, which removes molecular sieve fines from the dry gas stream. After a time in service, the molecular sieve becomes exhausted and attracts no more water on to its surface. At this point the molecular sieve requires to be regenerated. This is done by passing a stream of hot dry gas over the molecular sieve bed, driving off the water, which has accumulated, on its surface. The hot dry gas is obtained by heating a dry gas stream in a direct fired heater, a steam heated exchanger or by heating it against a medium such as the exhaust from a gas turbine. The spent regeneration gas is recovered for use in fuel gas systems or re-used in the process. When all the moisture has been driven off the molecular sieve bed, the bed needs to be cooled to ambient temperature before being returned to service. A cold dry gas stream is used to achieve this cooling and this spent gas stream is also used as fuel gas or elsewhere in the process. Following cooling the bed can be returned to service or put on standby. For a three dryer system the regeneration and changeover cycle comprises the following steps: I. (i) Depressurization 30 minutes II. (ii) Hot Regeneration 3 hours 30 minutes III. (iii) Bed Cooling 2 hours 30 minutes IV. (iv) Repressurization 30 minutes V. (v) Standby 45 minutes VI. (vi) 3 Bed Operation 15 minutes Control of the valves associated with the dryer regeneration and changeover sequence can be done using either an automatic timer program or a dedicated microprocessor program on the plant control system.

6.3.3 Feed Gas Chiller

This is typically a kettle-type exchanger where the feed gas is chilled to between 21

oC and 25

oC against refrigerant under level control in the shell side.

6.3.4 Feed Dryer Separator

Liquids (water and heavier hydrocarbons) are condensed and separated in this vessel. Water and liquid hydrocarbon are disposed of separately from this vessel and gas passes forward for further drying in the molecular sieve gas dryers.

6.3.5 Molecular Sieve Beds

Molecular sieve (mole sieve) is an alumino-silicate material with a very small pore size. This pore size is such that hydrocarbon gas will pass through while water will be attracted on to the surface of the mole sieve. The mole sieve is generally in pellet form, supported on a clay binder. The mole sieve beds are contained within a pressure vessel and to ensure efficient distribution of the gas through the mole sieve, a gas distributor nozzle is supplied at the gas inlet. A similar distributor nozzle is provided at the regeneration gas inlet. A series of inert ceramic balls is used to support the mole sieve at inlet and outlet and further increase the efficiency of gas distribution and help to prevent channeling.

6.3.6 Regeneration Gas Heater

A heater is required to supply the necessary heat to the regeneration gas. This heater can be direct fired, a conventional tube and shell exchanger using a suitable heat transfer medium or, in some specialist applications, the exhaust from a combustion gas turbine system. In all cases the heater must be sized to provide heating for all the required regeneration gas at the required temperature. Regeneration gas temperatures are generally in the range 250°C to 260°C.

6.3.7 Regeneration Gas Coolers

Typically, spent regeneration gas is disposed of to a fuel gas system or to elsewhere in the process. In either case this regeneration gas needs to be cooled to condense the water driven off and picked up by the regeneration gas in the regeneration process.

This is most efficiently accomplished in two stages: by using an air cooler followed by a water-cooled tube and shell exchanger.

6.3.8 Regeneration Gas Knock-out Drum

Water condensed in the regeneration gas air and water coolers is knocked out in the regeneration gas knockout drum. This vessel is fitted with a level control valve, which disposes of liquid to a separator or dirty sewer system. A demister pad prevents water droplets being carried over in the gas.

+

Figure 6.10 - Three Dryer System

7 Pipelines

7.1 History

For many centuries pipelines have been used to carry water for industrial and domestic use. Oil and gas pipelines are a much more recent development and although it is reported that the Chinese used bamboo lines to transport gas from seepages around the year 900 CE, modern hydrocarbon-carrying pipelines date only from the latter part of the 19th Century. In 1876 a pipeline was laid to carry natural gas from Kane, Pennsylvania to Buffalo, New York. This pipeline was 20 centimetres in diameter and some 140 kilometres long. An oil pipeline 15 centimetres in diameter and 170 kilometres long was laid from Bradford, Pennsylvania to Allentown, Pennsylvania in 1879. These early pipelines were made from threaded lengths of steel pipe and were screwed together by workers using large tongs. It was not until the 1920s that welding pipelines become common construction practice. Also, in the 1920s, oxy-acetylene welding was introduced, only to be superseded by electric welding later in the decade. Welding technology and inspection techniques have since developed to keep pace with the demands of new pipeline materials, vastly increased pipeline distances, greater pipeline diameters and the demands of off-shore and Arctic environments. In the early 1950s major pipelines were built in Canada and the Trans Arabia Pipeline (the Tapline) was built to carry crude oil from the Persian Gulf to the Mediterranean Sea. As it became apparent that oil and gas could be moved economically and efficiently using pipelines, the expansion of the world’s pipeline system expanded rapidly. Significant pipelines now include the Trans-Alaska pipeline and the pipeline system carrying gas from Siberia to Europe.

7.2 Types of Pipeline

Pipelines can be categorized in three main groups:

gathering

transmission

distribution. Other pipelines are required in oil and gas fields to inject water, gas or other fluids into the reservoir to enhance hydrocarbon recovery.

Smaller diameter pipelines called flowlines are used to gather oil and gas and to transport them to processing facilities in the field. These field facilities export product through larger diameter transmission pipelines to refineries or processing centres. Distribution networks made up of smaller diameter pipelines and metering facilities are used to finally deliver product to domestic or industrial users.

7.3 Pipeline Materials

While steel is the most common material used for the construction of pipelines in hydrocarbon service, other materials such as PVC can be used in a limited number of specialist applications. Pipe thickness and diameter are determined by the pressure and flows required through the pipeline. The selection of pipe thickness and diameter is always made on economic grounds and pipe weight per metre is an important consideration in this respect.

7.4 Pipeline Protection

The huge investment in pipeline systems, which include pipe, pumps, compressors and drivers as well as other equipment, makes protection of pipelines of critical importance. To protect pipelines internally, coatings are applied. The type of coating depends on the service to which the pipeline is put and the length of time it is expected to be in service. A common method of protecting pipeline is to lay the pipeline underground. Buried pipelines are usually externally coated to prevent corrosion and since maintenance of underground pipelines is particularly costly, further steps are taken to reduce corrosion. One such method of protection is cathodic protection. Corrosion of underground steel pipeline can result from the flow of electrical current between areas of different electrical potential. This current flows from an area of higher potential through an electrolyte to an area of lower potential. The area of lower potential (the anode) will be corroded and the area of higher potential will not be corroded. In the case of an underground pipeline, the soil is the electrolyte. These areas of different potential exist along the full length of a pipeline. The magnitude of the potential difference depends, among other factors, on the soil conditions. In a cathodic protection system, anodes are installed and an electrical current is made to flow between the pipeline and the anodes so that the pipeline becomes more electronically negative. The pipeline becomes the cathode of the system and its corrosion rate is decreased. The anodes (the part of the system to become corroded) are sacrificed.

Power requirements for a cathodic protection system are very small and in remote locations solar power is often used for this purpose.

7.5 Pipeline Operation

Oil and gas carrying pipelines have a good safety record and pipeline operations are regarded among the safest of industrial operations. This is largely due to the operation of pipeline leak detection systems. Traditionally overground pipelines were inspected visually, often by aircraft. This is not possible, however, in the case of underground or sub-sea pipelines. Leak detection is accomplished in these cases using sophisticated instrumentation and monitoring techniques. Metering accuracy plays a key role in the leak detection; an important way to detect leaks being direct monitoring of pressure drop and volume loss in a pipeline. Acoustic emission systems use the noise generated by fluid flow through pipelines to detect and locate leakage. This system can be used to continuously monitor for leaks. Detectors are installed at points in the pipeline, which pick up noises in the pipeline. These are transmitted to a system, which compares the noises to normal pipeline background noise. Differences in noise, indicating leakage, generate an alarm. Instrumented (intelligent) 'pigs' can also be used to detect pipeline leakage. A leak-detecting pig can be moved to various positions in the pipeline by the fluid flowing in the pipeline. When stopped at a test point, pressure is equalized in the test segments. If a leak exists, fluid will flow through the pig in the direction of the leaking segment.

8 Pipeline Pigs

8.1 General

Refer to Figure 8.1. Pipeline pigs are used for a number of purposes in oil and gas pipelines, including:

wax, water and dirt removal

product separation

pipeline inspection and leak detection

application of internal coatings. Pigs and spheres are transported through the pipeline by the pressure of the flowing liquid. A pig usually consists of a steel body with rubber or plastic cups attached to seal between the pig and the pipe internal wall. Brushes and scrapers can be attached to the pig for pipeline cleaning. The brushes and scrapers on a pipeline pig remove dirt and wax from pipe internals and several passes might be required to clean a section of pipe adequately. This type of cleaning pig contains holes which allow fluid to bypass the pig and to prevent build-up of debris in front of the pig which might cause plugging. Pipelines are often pigged initially after construction and prior to hydrostatic testing to push out air and to prevent mixing of air with the test water. Following testing, the test water is displaced by the pipeline fluid, a pig running between the two to keep them separate. Pigs can be fitted with instrumentation, which can detect leaks or construction faults in a pipeline such as dents or buckles. In pigging operations care must be taken to avoid foreign material or debris being introduced into compressor pumping systems. Instrumentation lines must also be protected during pigging operations.

8.2 Pig Launching and Receiving

Refer to Figure 8.2. To introduce the pig into the pipeline and to recover the pig after pigging operations, specialist equipment is required. This equipment comprises a launcher at the upstream end and a receiver at the downstream end. The allowable distance between launcher and receiver depends on the service, local operating procedures, material used in the pig and the location of pumping or compressor stations.

A key factor in determining the distance between launcher and receiver is the amount of lubrication in the pipeline. Gas having lower lubricating properties than oil or hydrocarbon condensate, the distance between traps is less for gas pipelines. In gas transmission pipelines the maximum distance between pigging stations has been recommended as 160 kilometres. In crude oil systems the recommended distance is 450 kilometres for pigs and 600 kilometres for spheres. These distances, however, represent extremes and the actual distance depends on local conditions.

Figure 8.1 - Types of Pig

Figure 8.2 - Typical Scraper Pig Launcher (Liquid)

9 Liquid Product Storage

9.1 General

Constraints on the export of product by pipelines or other means dictates a requirement for product storage. In addition, there is a need for storage for various chemicals used in the process and for the storage of by-products prior to disposal. Typical of the above are produced water and condensate product. Gas storage, either as liquefied petroleum gases or as liquefied natural gas, is highly specialized and is not considered in this section of the training module.

9.2 Cone Roof Tanks

Refer to Figure 9.1. A cone roof tank has a fixed sloping roof with a central apex. This type of tank is used for storing low volatility liquids at atmospheric pressure. Typical uses for the cone roof tank include storage for:

water

slops

caustic solutions

diesel. The roof is fixed and so requires protection from over-pressure or vacuum conditions. Breather vents or valves are used to provide this protection and are particularly important during tank loading or discharging operations.

9.3 Floating Roof Tanks

Refer to Figure 9.2. Floating roof tanks are the most common type of tank to be found in hydrocarbon service. They are used for storing liquids with a high volatility such as:

crude oil storage

light naphtha

heavy naphtha

jet fuel

gasoline

kerosene

hydrocarbon condensate. The tank comprises a tank shell and a roof supported by a pontoon, which floats on the tank contents.

The shell of the tank is slightly larger than the circumference of the pontoon and the space between is sealed with a flexible fabric. If this fabric is worn or not tight fitting there is loss of vapour and a risk of fire at the tank rim. The pontoon is designed with buoyancy compartments to allow the roof to float on top of the tank contents and rise and fall with rising or falling tank contents.

9.4 Tank Construction

Most tanks are constructed on-site by welding steel plates to form a vertical cylinder. Tank foundations must be capable of bearing the downward weight of a fully laden tank for several years. The area should have good drainage to avoid collection of water around the tank base, which might be a cause of corrosion. A bund wall capable of containing liquid spillage and to prevent the propagation of fire is used to separate tanks.

Figure 9.1 - Cone Roof Tank

Figure 9.2 - Floating Roof Tank