Chapter_01[Crude Oil Treating Systems1]

CHAPTER 1

Crude Oil Treating Systems

1.1 Introduction

Conditioning of oil-field crude oils for pipeline quality is complicatedby water produced with the oil. Separating water out of produced oil isperformed by various schemes with various degrees of success. Theproblem of removing emulsified water has grown more widespreadand oftentimes more difficult as production schemes lift more waterwith oil from water-drive formations, water-flooded zones, and wellsstimulated by thermal and chemical recovery techniques. This chap-ter describes oil-field emulsions and their characteristics, treatingoil-field emulsions so as to obtain pipeline quality oil, and equipmentused in conditioning oil-field emulsions.

1.2 Equipment Description

1.2.1 Free-Water Knockouts

Most well streams contain water droplets of varying size. If they collecttogether and settle to the bottom of a sample within 3–10 min, they arecalled “free water.” This is an arbitrary definition, but it is generallyused in designing equipment to remove water that will settle outrapidly. A free-water knockout (FWKO) is a pressure vessel used toremove free water from crude oil streams (Figure 1.1). They are locatedin the production flow path where turbulence has been minimized.Restrictions such as orifices, chokes, throttling globe valves, andfittings create turbulence in the liquids that aggravate emulsions. Freewater, at wellhead conditions, frequently will settle out readily to thebottom of an expansion chamber.

Sizing and pressure ratings for these vessels are discussed in the“Gas–Liquid and Liquid–Liquid Separation” volume, this series. Fac-tors affecting design include retention time, flow rate (throughput),temperature, oil gravity (as it influences viscosity), water drop size

distribution, and emulsion characteristics. Abnormal volumes of gasin the inlet stream may require proportionately larger vessels as thesegas volumes affect the throughput rate. A simple “field check” todetermine retention time is to observe a fresh sample of the wellheadcrude and the time required for free water to segregate.

In installations where gas volumes vary, a two-phase separator isusually installed upstream of the FWKO. The two-phase separatorremoves most of the gas and reduces turbulence in the FWKO vessel.The FWKO usually operates at 50 psig (345 kPa) or less due to the ves-sel’s location in the process flow stream. Internals should be coated orprotected from corrosion since they will be in constant contact withsalt water.

1.2.2 Gunbarrel Tanks with Internal and External Gas Boots

The gunbarrel tank, sometimes called a wash tank, is the oldestequipment used for multi-well onshore oil treating in a conventionalgathering station or tank battery. Gunbarrel tanks are very commonin heavy crude applications such as in Sumatra and East Kalimantan,Indonesia, and in Bakersfield, California.

The gunbarrel tank is a vertical flow treater in an atmospherictank. Figure 1.2 shows a “gunbarrel” tank with an internal gas boot.Typically, gunbarrels have an internal gas separating chamber or“gas boot” extending 6–12 ft (2–4 m) above the top of the tank, wheregas is separated and vented, and a down-comer extending 2–5 ft (0.6–1.5 m) from the bottom of the tank. A variation of the above gunbarrelconfiguration is a wash tank with an “external” gas boot. This configu-ration is preferred on larger tanks, generally in the 60,000-barrel range,where attaching an internal gas boot is structurally difficult. In eithercase, the gunbarrel tank is nothing more than a large atmosphericsettling tank that is higher than downstream oil shipping and waterclarifier tanks. The elevation difference allows gravity flow into thedownstream vessels.

LC

Water Outlet

Inlet

Emulsion

Water

Gas

Gas and EmulsionOutlet

FIGURE 1.1. Cutaway of a free-water knockout.

2 Emulsions and Oil Treating Equipment

Because gunbarrels tend to be of larger diameter than verticalheater-treaters, many have elaborate spreader systems that attemptto create uniform (i.e., plug) upward flow of the emulsion to take max-imum advantage of the entire cross section. Spreader design is impor-tant to minimize the amount of short-circuiting in larger tanks.

The emulsion, flowing from an upstream separator and possiblya heater, enters the top of the gas separation section of the gas boot.The gravity separation section removes flash gas and gas liberated asa result of heating the emulsion. The emulsion flows down thedown-comer to a spreader, which is positioned below the oil–waterinterface. Exiting at the bottom of the down-comer, the emulsion risesto the top of the surrounding layer of water. The water level is con-trolled by a water leg or automatic level control. The emulsion passagethrough the water helps collect the entrained water and converts

Gas

Oil

Water

Emulsion

GasOutlet

Emulsion Inlet

Adjustable Interface

Nipple

Weir Box

Gas Equalizing Line

Gas Separating Chamber

Water Wash Section

Oil Settling Section

OilOutlet

Spreader

Water Outlet

Em

ulsi

on

FIGURE 1.2. Gunbarrel with an internal gas boot.

Crude Oil Treating Systems 3

the emulsion into distinct oil and water layers. Oil accumulates at thetop and flows out through the spillover line into the oil settling tank.Water flows from the bottom of the tank, up through the water leg,and into a surge or clarifier tank. The height of the water leg regulatesthe amount of water retained in the vessel. The settling time in thevessel for the total fluid stream is usually 12–24 h. Most gunbarrelsare unheated, though it is possible to provide heat by heating the incom-ing stream external to the tank, installing heating coils in the tank, orcirculating the water to an external or ‘jug’ heater in a closed loop. It ispreferable to heat the inlet so that more gas is liberated in the boot,although this means that fuel will be used in heating any free water inthe inlet.

The height of the externalwater leg controls the oil–water interfaceinside the vessel and automatically allows clean oil and produced waterto exit the vessel. Example 1.1 illustrates this design consideration.

1.2.3 Determination of External Water Leg Height

Given:

Oil gravity at 60 �F 36 �APIWater specific gravity 1.05Height of oil outlet 23 ftHeight of interface level 10 ft (for this example)Height of water outlet 1 ftFigure 1.3 Gunbarrel schematic

Solution:Determine the oil specific gravity.

Oil specific gravity ¼ 141:5

131:5þ �API¼ 141:5

131:5þ 36¼ 0:845

1. Determine the oil gradient.

Since the charge in the pressure with depth for fresh water is0.433 psi/ft of depth, the change in pressure with depth of fluid whosespecific gravity is SG would be 0.433 (SG); thus, the oil gradient is

Oil gradient ¼ ð0:433Þð0:845Þ ¼ 0:366 psi=ft:

2. Determine the water gradient.

Water gradient ¼ ð0:433Þð1:05Þ ¼ 0:455 psi=ft:


3. Calculate the height of the oil and the height of the water inthe tank.

Ho ¼ height of oil outlet� height of interface level ¼ 23� 10 ¼ 13 ft

Hw ¼ height of interface level� height of water outlet ¼ 10� 1 ¼ 9 ft:

4. Perform a pressure balance.

Hydrostatic pressureinside tank

� �¼ Hydrostatic pressure

in the water leg

� �;

ð13Þð0:366Þ þ ð9Þð0:455Þ ¼ ðHÞð0:455Þ;

H ¼ ð13Þð0:366Þ þ ð9Þð0:455Þ0:455

¼ 19:5 ft:

Gas

Oil

Water

Emulsion

GasOutlet

Emulsion Inlet

AdjustableInterface

Nipple

Weir Box

Gas EqualizingLineGas Separating

Chamber

OilOutlet

Spreader

WaterOutlet

Em

ulsi

on

H

HW

HO

FIGURE 1.3. Determination of external water leg height, H.


The design details for the spreader, water leg, and gas separation sec-tion vary for different manufacturers. These details do not signifi-cantly affect the sizing of the tank, provided the spreader minimizesshort-circuiting. No matter how careful the design of the spreaders,large wash tanks are very susceptible to short-circuiting. This is dueto temperature and density differences between the inlet emulsionand the fluid in the tank, solids deposition, and corrosion of thespreaders.

Standard tank dimensions are listed in API Specification 12F(Shop Welded Tanks), API Specification 12D (Field Welded Tanks),and API Specification 12B (Bolted Tanks). These dimensions areshown in Tables 1.1, 1.2, and 1.3, respectively.

Gunbarrels are simple to operate and, despite their large size, arerelatively inexpensive. However, they have a large footprint, which iswhy they are not used on offshore platforms. Gunbarrels hold a large

TABLE 1.1Shop welded tanks (API specification 12 F)

(a) Field Units

NominalCapacity(bbl)

ApproximateWorking

Capacity (bbl)

OutsideDiameter(ft–in.)

Height(ft–in.)

Height ofOverflowConnection (ft–in.)

90 72 7–11 10 9–6100 79 9–6 8 7–6150 129 9–6 12 11–6200 166 12–0 10 9–6210 200 10–0 15 14–6250 224 11–0 15 14–6300 266 12–0 15 14–6500 479 15–6 16 15–6

(b) SI Units

NominalCapacity(bbl)

ApproximateWorking

Capacity (m3)

OutsideDiameter

(m)Height(m)

Height ofOverflow

Connection (m)

90 11.4 2.41 3.05 2.90100 12.6 2.90 2.44 2.29150 20.5 2.90 3.66 3.51200 26.4 3.66 3.05 2.90210 31.8 3.05 4.57 4.42250 35.6 3.35 4.57 4.42300 42.3 3.66 4.57 4.42500 76.2 4.72 4.88 4.72


volume of fluids, which is a disadvantage should a problem develop.When the treating problem is detected in the oil outlet, a large volumeof bad oil has already collected in the tank. This oil may have to betreated again, which may require large slop tanks, recycle pumps,etc. It may be beneficial to reprocess this bad oil in a separate treatingfacility so as to avoid further contamination of the primary treatingfacility.

Gunbarrels are most often used in older, low-flow-rate, onshorefacilities. In recent times, vertical heater-treaters have become soinexpensive that they have replaced gunbarrels in single-well

TABLE 1.2Field welded tanks (API specification 12D)

(a) Field Units

Nominal

Capacity

(bbl)

Design Pressure

(oz/in.2) Approximate

Working

Capacity (bbl)

Nominal

Outside

Diameter

(ft–in.)

Nominal

Height

(ft–in.)

Height ofOverflow

Line

Connection

(ft–in.)Pressure Vacuum

H-500 8 1/2 479 15–6 16–0 15–6750 8 1/2 746 15–6 24–0 23–6L-500 6 1/2 407 21–6 8–0 7–6H-1000 6 1/2 923 21–6 16–0 15–61500 6 1/2 1438 21–6 24–0 23–6L-1000 4 1/2 784 29–9 8–0 7–62000 4 1/2 1774 29–9 16–0 15–63000 4 1/2 2764 29–9 24–0 23–65000 3 1/2 4916 38–8 24–0 23–610,000 3 1/2 9938 55–0 24–0 23–6

(b) SI Units

NominalCapacity

(bbl)

Design Pressure

(kPa) ApproximateWorking

Capacity (m3)

Nominal

OutsideDiameter

(m)

NominalHeight

(m)

Height of

Overflow

LineConnection

(m)Pressure Vacuum

H-500 3.4 0.2 76.2 4.72 4.88 4.72750 3.4 0.2 118.6 4.72 7.32 7.16L-500 2.6 0.2 64.7 6.55 2.44 2.29H-1000 2.6 0.2 146.8 6.55 4.88 4.721500 2.6 0.2 228.6 6.55 7.32 7.16L-1000 1.7 0.2 124.6 9.07 2.44 2.292000 1.7 0.2 282.0 9.07 4.88 4.723000 1.7 0.2 439.4 9.07 7.32 7.165000 1.3 0.2 781.6 11.79 7.32 7.1610,000 1.3 0.2 1580.0 16.76 7.32 7.16


TABLE 1.3Bolted tanks (API specification 12B)

(a) Field Units

NominalCapacity(42-gal bbl)

Numberof Rings

InsideDiametera

(ft–in.)

Height ofShellb

(ft–in.)

CalculatedCapacityc

(42-gal bbl)

100 1 9–2 34 8–12 96

200 2 9–2 34 16–1 192

300 3 8–2 24–1 12 287

250 1 15–4 58 8–12 266

High 500 2 15–4 58 16–1 533

750 3 15–4 58 24–1 1

2 799

Low 500 1 21–6 12 8–12 522

High 1000 2 21–6 12 16–1 1044

1500 3 21–6 24–1 12 1566

Low 1000 1 29–8 58 8–12 944

2000 2 29–8 58 16–1 1987

3000 3 29–8 58 24–1 1

2 2981

5000 3 38–7 58 24–1 1

2 503710,000 3 54–11 3

4 24–2 10,218

(b) SI Units

NominalCapacity(42-gal bbl)

Numberof Rings

InsideDiameterd

(m)

Height ofShellb

(m)

CalculatedCapacityc

(m3)

100 1 2.81 2.45 15.3200 2 2.81 4.90 30.5300 3 2.81 7.35 45.6250 1 4.69 2.45 42.3High 500 2 4.69 4.90 84.7750 3 4.69 7.35 127.0Low 500 1 6.57 2.45 83.0High 1000 2 6.57 4.90 166.01500 3 6.57 7.35 249.0Low 1000 1 9.06 2.45 158.02000 2 9.06 4.90 315.93000 3 9.06 7.30 473.95000 3 11.78 7.30 800.810,000 3 16.76 7.37 1624.5

aThe inside diameter is an approximate dimension. The values shown are 2 in. less thanthe bottom bolt-circle diameters.bShell heights shown do not include the thickness of the gasket.cThe calculated capacity is based on the inside diameter and height of shell.dThe inside diameter is an approximate dimension. The values shown are less than thebottom bolt-circle diameters.


installations. On larger installations onshore in warm weather areas,gunbarrels are still commonly used. In areas that have a winter seasonthey tend to become too expensive to keep the large volume of oil at ahigh enough temperature to combat potential pour-point problems.

1.2.4 Horizontal Flow Treaters

Horizontal flow treaters are not common. Figure 1.4 illustrates onedesign, which consists of a cylindrical treating tank incorporatinginternal baffles. The internal baffles establish a horizontal flow pat-tern in the cylindrical tank, which is more efficient for gravity separa-tion than vertical flow and is less subject to short-circuiting.

The oil, emulsion, and water enter the vessel and must followthe long flow path between the baffles. Separation takes place in thestraight flow areas between the baffles. Turbulence coupled with highflow velocities prevents separation at the corners, where the flowreverses direction. Tracer studies indicate that approximately twothirds of the plan area of the tank is effective in oil–water separation.

In addition to gravity separation, the emulsion must be collectedand held in the treater for a certain retention time so that the emul-sion will break. In horizontal flow treaters, the emulsion collects

Oil

Water hw/zInlet

hw/z

A-A

ho

B-B

Water

Oil Oil Out

Water Out

Outlet

Inlet

B

A

B

A

PLAN VIEW

FIGURE 1.4. Plan view of a cylindrical treating tank incorporating internalbaffles that establish horizontal flow.


between the oil and water; however, the horizontal flow pattern tendsto sweep the emulsion toward the outlets. The emulsion layer maygrow much thicker at the outlet end of the treater than at the inletend. Accordingly, it is much easier for the emulsion to be carriedout of the vessel with the oil.

1.2.5 Heaters

Heaters are vessels used to raise the temperature of the liquid before itenters a gunbarrel, wash tank, or horizontal flow treater. They areused to treat crude oil emulsions. The two types of heaters commonlyused in upstream operations are indirect fired heaters and direct firedheaters. Both types have a shell and a fire tube. Indirect heaters have athird element, which is the process flow coil. Heaters have standardaccessories such as burners, regulators, relief valves, thermometers,temperature controllers, etc.

Indirect Fired Heaters

Figure 1.5 shows a typical indirect fired heater. Oil flows throughtubes that are immersed in water, which in turn is heated by a firetube. The heat may be supplied by a heating fluid medium, steam,or electric immersed heaters. Indirect heaters maintain a constanttemperature over a long period of time and are safer than the directheater. Hot spots are not as likely to occur if the calcium content ofthe heating water is controlled. The primary disadvantage is thatthese heaters require several hours to reach the desired temperatureafter they have been out of service.

Emulsion InletEmulsion Outlet

Heat or Fire

Water

Emulsion

FIGURE 1.5. Cutaway of a horizontal indirect fired heater.


Direct Fired Heaters

Figure 1.6 shows a typical direct fired heater. Oil flows through aninlet distributor and is heated directly by a fire box. The heat maybe supplied by a heating fluid medium, steam, or an electric immersedheater. Direct heaters are quick to reach the desired temperature, areefficient (75–90%), and offer a reasonable initial cost. Direct fired hea-ters are typically used where fuel gas is available and high volume oiltreating is required. On the other hand, they are hazardous and requirespecial safety equipment. Scale may form on the oil side of the firetube, which prevents the transfer of heat from the fire box to the oilemulsion. Heat collects in the steel walls under the scale, whichcauses the metal to soften and buckle. The metal eventually rupturesand allows oil to flow into the fire box, which results in a fire. Theresultant blaze, if not extinguished, will be fed by the incoming oilstream.

1.2.6 Waste Heat Recovery

A waste heat recovery heater captures waste heat from the exhauststacks of compressors, turbines, generators, and large engines. Heatexchangers are used to transfer this heat to a heating fluid medium,which in turn is used to heat the crude oil emulsion.

1.2.7 Heater-Treaters

Heater-treaters are an improvement over the gunbarrel and heater sys-tem. Many designs are offered to handle various conditions such as

Oil Outlet

Crude Oil Inlet

Crude Oil Emulsion

Heat or Fire

FIGURE 1.6. Cutaway of a horizontal direct fired heater.


viscosity, oil gravity, high and low flow rates, corrosion, and coldweather. When compared to gunbarrels, heater-treaters are less expen-sive initially, offer lower installation costs, provide greater heat effi-ciency, provide greater flexibility, and experience greater overallefficiency. On the other hand, they are more complicated, provide lessstorage space for basic sediment, and are more sensitive to chemicals.Since heater-treaters are smaller than other treating vessels, theirretention times are minimal (10–30 min) when compared to gunbar-rels and horizontal flow treaters.

Internal corrosion of the down-comer pipe is a common problem.Build-up of sediment on the walls or bottom of the treater can causethe interface levels to rise and liquid to carry over and/or oil to exitthe treater with salt water. Bi-annual inspections should be performedto include internal inspection for corrosion, sediment build-up, andscale build-up.

1.2.8 Vertical Heater-Treaters

The most commonly used single-well treater is the vertical heater-treater, which is shown in Figure 1.7. The vertical heater-treater con-sists of four major sections: gas separation, FWKO, heating and water-wash, and coalescing-settling sections. Incoming fluid enters the topof the treater into a gas separation section, where gas separates fromthe liquid and leaves through the gas line. Care must be exercised tosize this section so that it has adequate dimensions to separate thegas from the inlet flow. If the treater is located downstream of a sepa-rator, the gas separation section can be very small. The gas separationsection should have an inlet diverter and a mist extractor.

The liquids flow through a down-comer to the base of the treater,which serves as a FWKO section. If the treater is located downstreamof a FWKO or a three-phase separator, the bottom section can be verysmall. If the total wellstream is to be treated, this section should besized for 3–5 min retention time to allow the free water to settleout. This will minimize the amount of fuel gas needed to heat the liq-uid stream rising through the heating section. The end of the down-comer should be slightly below the oil–water interface so as to‘water-wash’ the oil being treated. This will assist in the coalescenceof water droplets in the oil.

The oil and emulsion rise through the heating and water-washsection, where the fluid is heated (Figure 1.8). As shown in Figure 1.9,a fire tube is commonly used to heat the emulsion in the heating and


Water

Oil

TreatedOil Out

EmulsionInlet

Water Out

Drain

Coalescing

Section

Gas Outlet

Spreader

Fire Tube

Oil/WaterInterface

Gas Equalizer

Mist Extractor

d

h

FIGURE 1.7. Simplified schematic of a vertical heater-treater.


water-wash section. After the oil and emulsion are heated, the heatedoil and emulsion enter the coalescing section, where sufficient reten-tion time is provided to allow the small water droplets in the oil con-tinuous phase to coalesce and settle to the bottom. As shown inFigure 1.10, baffles are sometimes installed in the coalescing sectionto treat difficult emulsions. The baffles cause the oil and emulsion

Oil Outlet

Down-Comer

Water Leg

Baffles

Oil Leg(Heat Exchanger)

Fire Tube

OilOut

FluidIn Water

Out

Drain

Gas OutFree-WaterKnockoutSection

Heatingand

Water-Wash Section

OilSettlingSection

GasSeparation

Section

FIGURE 1.8. Three-dimensional view illustrating oil and emulsion risingthrough the heating and water-wash.


to follow a back-and-forth path up through the treater. Heating causesmore gas to separate from the oil than is captured in the condensinghead. Treated oil flows out the oil outlet, at the top of the coalescingsection, and through the oil leg heat exchanger, where a valve controlsthe flow. Heated clean oil preheats incoming cooler emulsion in theoil leg heat exchanger (Figure 1.11). Separated water flows out throughthe water leg, where a control valve controls the flow to the watertreating system (Figure 1.12).

As shown in Figure 1.13, any gas flashed from the oil due to heat-ing, is captured on the condensing head. Any gas that did not con-dense flows through an equalizing line to the gas separation section.

Hot Air

Fire Tube

Emulsion

Stack

Thermometer

Fuel Gas InletThermostat

Safety Fuel Gas Scrubber

FIGURE 1.9. Cutaway showing a typical fire-tube that heats the emulsion inthe heating and water-wash section.


As shown in Figure 1.14, a vane-type mist extractor removes the liq-uid mist before the gas leaves the treater. The gas liberated whencrude oil is heated may create a problem in the treater if it is not ade-quately designed. In vertical heater-treaters the gas rises through thecoalescing section. If a great deal of gas is liberated, it can createenough turbulence and disturbance to inhibit coalescence. Equallyimportant is the fact that small gas bubbles have an attraction for sur-face-active material and hence water droplets. Thus, they tend to keep

FIGURE 1.10. Baffles, installed in the coalescing section, cause the emulsionto follow a back-and-forth path up through the oil settling section.


the water droplets from settling out and may even cause them to carryover to the oil outlet.

The oil level is maintained by pneumatic or lever-operated dumpvalves. The oil–water interface is controlled by an interface level con-troller or an adjustable external water leg.

Standard vertical heater-treaters are available in 20- and 27-ft(6.1 and 8.2 m) heights. These heights provide sufficient static liquidhead so as to prevent vaporization of the oil. The detailed designof the treater, including the design of internals (many features ofwhich are patented), should be the responsibility of the equipmentsupplier.

CleanOil In

Well FluidsOut

CleanOil Out

IncomingWell Fluids

FIGURE 1.11. Heated clean oil preheats incoming cooler emulsion in the oilleg heat exchanger.


1.2.9 Coalescing Media

It is possible to use coalescing media to promote coalescence of thewater droplets. These media provide large surface areas upon whichwater droplets can collect. In the past the most commonly used coa-lescing media was wood shavings or ‘excelsior,’ which is also referredto as a ‘hay section.’ The wood excelsior was tightly packed to createan obstruction to the flow of the small water droplets and promoterandom collision of these droplets for coalescence. When the dropletswere large enough, they fell out of the flow stream by gravity.Figure 1.15 shows a vertical heater-treater utilizing an excelsior.

Oil Dump Valve

Heat Exchanger

Oil Outlet

FIGURE 1.12. Cutaway illustrating oil and water legs.


The use of an “excelsior” allowed lower treating temperatures.However, these media had a tendency to clog with time and weredifficult to remove. Therefore, they are no longer used.

1.2.10 Horizontal Heater-Treaters

For most multi-well flow streams, horizontal heater-treaters are nor-mally required. Figure 1.16 shows a simplified schematic of a typicalhorizontal heater-treater. Design details vary from manufacturer tomanufacturer, but the principles are the same. The horizontalheater-treater consists of three major sections: front (heating andwater-wash), oil surge chamber, and coalescing sections.

Gas Equalizing Line

Fluid Inlet

CondensingHead

Oil Outlet

HeatExchanger

FIGURE 1.13. Gas, flashed from the oil during heating, is captured on thecondensing head.


Incoming fluids enter the front (heating and water-wash) sectionthrough the fluid inlet and down over the deflector hood (Figure 1.17)where gas is flashed and removed. Heavier materials (water and solids)flow to the bottom while lighter materials (gas and oil) flow to the top.Free gas breaks out and passes through the gas equalizer loop to the gasoutlet. As shown in Figure 1.18, the oil, emulsion, and free water passaround the deflector hood to the spreader located slightly below theoil–water interface, where the liquid is “water-washed” and the freewater is separated. For low gas–oil-ratio crudes, blanket gas may berequired to maintain gas pressure. The oil and emulsion are heated asthey rise past the fire tubes and are skimmed into the oil surge chamber.

As free water separates from the incoming fluids in the front sec-tion, the water level rises. If the water is not removed, it will continueto rise until it displaces all emulsion and begins to spill over the weirinto the surge section. On the other hand, if the water level becomestoo low, the front section will not be able to water-wash the incomingoil and emulsion, which would reduce the efficiency of the treater.Therefore, it is important to accurately control the oil–water interface

Shell

Vanes

GasInlet

LiquidOutlet

FIGURE 1.14. Vane-type mist extractor removes the liquid mist before thegas leaves the treater.


in the front section. The oil–water interface is controlled by either aninterface level controller, which operates a dump valve for the freewater (Figure 1.19), or a resistance probe. If the water outlet valve sticksopen, all the water and oil run out, exposing the fire tube or heat source.

As shown in Figure 1.20, a level safety low shutdown sensor isrequired in the upper portion of the front (heating and water-wash)section. This sensor assures liquid is always above the fire tube.If the water dump valve malfunctions or fails open, the liquidsurrounding the fire tube will drop, thus not absorbing the heat gener-ated from the fire tube and possibly damaging the fire tube by over-heating. Thus, if the level above the fire tube drops, the level safetylow shutdown sensor sends a signal that closes the fuel valve feedingthe fire tube. It is also important to control the temperature of thefluid in the front (heating and water-wash) section. Therefore, a tem-perature controller, controlling the fuel to the burner or heat source,is required in the upper part of the heating–water-wash section(Figure 1.21).

Excelsior

FIGURE 1.15. Vertical heater-treater fitted with excelsior, between the baf-fles, which aids in coalescence of water droplets.


Next Page

Chapter_01[Crude Oil Treating Systems1]

Documents

Transcript of Chapter_01[Crude Oil Treating Systems1]