Crude Oil Dehydration and Desalting

17 Apr. 00

ADMA-OPCO On-site Training Course

PROCESS

Module - D 14

CRUDE OIL DEHYDRATION & DESALTING

Gap Elimination Program

D:\SO\wr\IHRDC-Modules\Module-D D:\SO\wr\IHRDC-Modules\Module-D14-Proc-CrudeOi 14-Proc-CrudeOilDehy.Desalt.do lDehy.Desalt.docc

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Process

Module - D 14



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Process

Module - D 14



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TABLE OF CONTENTS

I.

FREE WATER SEPARATION

II.

EMULSION

III. HEATER TREATER IV. ELECTROSTATIC TREATER PROCESS PLANT DESCRIPTION A. B. C. D. E.

Process Design Basis Principles of Process Principles of Operations Chemical Injection Main Control Loops


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OBJECTIVES Upon completion of the module the developee will be able to: ¾

Define the free water and water cut.

¾

Explain the differences between free water and emulsified water.

¾

Identify the emulsifying agents.

¾

Understand the crude oil dehydration and desalting process.

¾

Describe the heater treater and identify its sections and internals.

¾

Explain the dehydration and desalting parameters and their effect on water-oil emulsions.

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CRUDE OIL DEHYDRATION AND DESALTING I.

Free water separation •

•

•

The production facilities that include a treatment process, is concerned with oil and gas separation and treatment. The main reason for this is to meet the requirements and quality control. In oil fields, after the initial gas-oil separation process, the oil must be treated to remove water, salt.

•

The pipeline requirement for oil must have its water content reduce to 2% by volume.

•

All well streams contain water droplets of various sizes, it settles out as free water.

•

•

•

100 X Volume of free water = % water cut Total volume of liquid produced Free-water knockout is a separation vessel located along the flow stream at a point of minimum turbulence. The oil and water mixture is allowed sufficient time to separate.


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II.

Emulsion 1.

Emulsion

It is one of the liquids is spread out or dispressed, through out the other in the form of small droplets. 2.

Two Types of Emulsion

-

Water is dispressed in oil, water in oil emulsion [this the oil field emulsion].

-

Oil in water emulsion; Flight Emulsion “difficult to break” Loose Emulsion “easy to break”. This depends on the type and amount of emulsifying agent present.


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WATER IN OIL EMULSION


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3.

4.

Emulsifying Agents:

-

It is the substance that promotes the formation and stability of an emulsion.

-

It is collecting on the surface of water droplets and forming tough film which keeps the droplets from joining.

-

It includes asphalt, resins, paraffins and oil soluble organic acids.

Breaking an Emulsion:

-

To break an emulsion, the film must be neutralized or destroyed by using treatment methods;

-

This treating is done by; a)

Using various types of equipment. Free-water knockouts, separators. Heater Treaters, and Electro Static Treaters.

b) 5.

By adding chemicals to the emulsion immediately after it is produced.

Emulsion Stability:

The factors affecting Emulsion Stability are; -

Emulsifying Agent.

-

Viscosity of Oil.

-

A.P.I. Oil Gravity.

-

Water Percentage.

-

Agitation.

-

Droplet size.

-

Age of Emulsion.


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6.

Treating Emulsion:

It may include one or more of the following: -

Allowing Settling Time.

-

Applying Heat.

-

Injecting Chemicals.

-

Using Electricity or Mechanical Devices. •

Setting Time: It is affected by viscosity size of water droplets and gravity differential.

•

•

•

•

Applying Heat: -

Heat causes water droplet to move faster, it collide, heavier droplets form.

-

Heat lowers the viscosity of oil.

-

Heat speeds up chemical action; the water droplet expand and break the film of emulsifying agent.

-

Too much heat will; *

Waste energy.

*

Cause greater wear on the equipment.

Adding Chemicals: -

Emulsion breaking chemicals are injected into the well stream ahead of the oil treatment.

-

They react with film of emulsifying agent around water droplets, allowing the droplets to coalesce.

Using Electricity: -

To help the coalescing of water droplets,

-

It is usually used in conjunction with heat and chemicals.

Using Mechanical Devices The free water knock out is gravity type separator to remove excessive water from the produced oil. Heater treater is an example of using electricity and mechanical devices and chemical injection


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III.

Heater Treater Components 1.

External Components

Fire Box, Gas Supply Line: Stack, Thermometer, Thermowell Inlet Line, Gas Equalizer, Gas Dome, Gas Back – Pressure Valve. Oil Outlet, Oil Dump Valve. Water Outlet, Water Dump Valve. Interface Level Controllers, Drains. 2.

INTERNAL SECTIONS: *

Gas Separation Section Baffle, downcomer.

*

Free Water Knockout Section Water wash, flow spreader

*

Heating Section and its Weir

*

Settling Section “Coalescing Section” Flow spreader, weir, clean oil box.

*

Water Draw off Section


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IV.

Electrostatic Treater Process Plant Description

Purpose of the Elecrostatic Treater Process Plant Water is removed from the oil initially by three phase separators and the Spheroids. The oil then passes to the new Electrostatic Treatment Plant (ETPP) where more water and salt is removed. The ETPP will reduce the salt content in the effluent oil stream to 25 pounds per thousand barrels (25 PTB) and 0.15% water. The design oil charge rate is 295,000 BPD Umm Shaif and 378,000 Zakum plus 10%^ formation water. The total maximum rates are 324,500 Umm Shaif and 415,800 Zakum. The produced water removed from ETPP flows to the Sour Water De-oiling Plant (SWDP). The ETPP is supplied with fuel gas from ADGAS. Also fuel gas can be supplied from a Gas Sweetening Unit (GSU) and from Zakum Sour Gas. The ETPP is supplied with wash water from a Sea Water Oxygen Removal Plant (SWORP). Section 4.2

BASIC PRINCIPLES OF PROCESS

General

Desalting is a hot water extraction process. The salt or salt solution in a crude oil is diluted by adding wash water and then thoroughly mixing. In practice, the mixing stage can approach 100% efficiency and then the salt content of the desalted crude is dependent upon the amount or dilute solution left, and is given by the formula: Salt Content of Desalted crude in (PPM) = ( K1 X C1 ) + ( K2 X C2 ) X K3 K2 + K3 X 100 Where :

K1 is % of formation water in raw crude. C1 is salt content of formation water (in ppm). K2 is % of added dilution water. C2 is salt content of dilution water (in ppm) K3 is % of residual water in treated crude.

Note: To convert the ppm salt content of desalted crude to PTB (Pound per Thousand Barrel) use the equation: 1 PTB = approximately 3.436 ppm After mixing, the crude / salt water mixture enters the desalter where separation occurs. This separation is assisted by temperature, an electric field and / or demulsifier chemicals.


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Description The oil flow is similar for both Umm Shaif and Zakum crudes. The oil flow is pumped from the Horton spheres by the respective crude charge pumps. Oil and formation water enters the unit via two lines, one for each crude. The crude flows split into a minimum of three streams with a common spare stream for either crudes. The crude feed to each train is first heated in a tubular heat exchanger using steam as the heating medium. From the heat exchanger the oil flow passes through a gas fired heater. The inclusion of the steam heater is important since this minimizes the required heat capacity of the fired heater and reduces its gas side corrosion problems. The outlet temperature of the oil from the gas heater is 100 degrees F. The heated crude from each train then passes to the individual dehydration and desalting vessels. The crude flows through a mixing valve and into the lower section of the horizontal dehydration vessel. Recycled brine from the desalter is injected upstream of the mixing valve under level control from the desalter oil / water interface by the recycle pumps. On leaving the upper section of the dehydration vessel the crude flow then passes through another mixing valve in the lower section of the desalting vessel. De-oxygenated water pumped from the SWORP area is injected into the crude flow upstream the mixing valve, under flow control. A normal injection rate is about 5.0% of the crude flow. The brine is drawn-off under level control and pumped to the dehydration vessel. On leaving the top section of the desalter the crude join the other streams in a common header and leaves the battery limits via a 30” line to the H2S stripping unit. The pressure drop across the mixing valves is manually adjusted to ensure good mixing with the wash water. A normal range is 7-30 psig depending on throughput.


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Desalter / Dehydrator Vessels Each of the vessels is provided with high and low oil / water interface alarms independent of the interface level control system. Try cocks are provided for testing and checking the interface level. Interface drains are used to draw off any emulsion formed and the emulsions are treated in a separate vessel by steam heating. Any recovered oil is pumped back to the crude oil outlet lines. Water being returned to the SWDP. There are 6 x 4” sand drains on each vessel that are used to draw off any solids accumulating in the base of the vessels. The solids are removed by water jetting and separation takes place in the desander vessel. On the vessels there is a locally mounted panel with light signals and ammeters associated with the dehydration and desalting operation.


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SEA WATER OXYGEN REMOVAL PLANT

Purpose of the sea water oxygen removal plant, is to provide the ETPP with sufficient and constant stream of wash water for the treatment process. The SWORP strips oxygen from the raw sea water and doses it wit biocide thus limiting corrosion and bioglogical growth within the D&D system. The plant is illustrated by attached flow diagram identifying the main four sections of SWORP. i)

Chlorination Section

ii)

Filtration

iii)

Oxygen Removal

iv)

Chemical Injection


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SOUR WATER DE-OILING PLANT

As the resulting effluent water contains much salt, hydrogen sulphide and residual oil, and it is treated in the (SWDP) to remove the bulk of residual oil before discharging to sea 1.5 km offshore. The attached figure of (SWDP) is used to illustrate the purpose of SWDP.


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A) PROCESS DESIGN BASIS

1.

Crude Oil Properties Zakum

Umm Shaif

41.0 – 41.6

38.0 – 38.5

4.1

5.7

2.9

3.8

Specific Heat (Btu / Ib / F)

0.47

0.47

% H2S (Wt.)

0.009 – 0.013

0.052 – 0.085

Wax point ( 0 F )

61 – 68

66 - 75

0

Gravity at 60 F (API) 0

Viscosity at 70 F (CST) 0

Viscosity at 100 F (CST) 0

2.

3.

Typical Properties of Formation Water Zakum

Umm Shaif

pH (average)

6.8

5.1

pH *range)

5.0

4.6 – 6.4

Total dissolved solids (ppm Wt.)

250,000

250,000

H2S content (Max. in ppm Wt.)

600

600

Crude Oil Charge to Gas / Oil Separators and Spheroids Zakum

Umm Shaif

Oil Charge Rate (MSTBD)

378*

295*

Formation Water (MBD)

0 – 75.6

0 – 59

Note: * These crude production rates have been brought into line with the capacity of the ETPP.


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4.

Crude Oil Charge to ETPP Zakum

Umm Shaif

Oil charge rate (MSTBD)

378

295

Formation Water (MBD)

0 – 37.8

0 – 29.5

415.8

324.5

Pressure ex. Feed pumps (psig)

183

197

Pressure at ETPP inlet (Winter* Summer **)

55* - 82**

53* - 73**

Total Rate (MBD)

Note: These crude oil flow rates are based on required average production rates plus an allowance for curtailments due to bad weather etc…)

5.

6.

Crude Oil Charge to Crude Stripping Units ( from ETPP ) Zakum

Umm Shaif

Pressure ex. ETPP (psig)

64

75

Pressure at CSU inlet control Valve (psig)

15

15

Temperature (0F)

90 – 100

90 - 100

Crude Oil Product Quality ( from ETPP ) Zakum

Umm Shaif

PS & W in crude (% vol.)

0.15

0.15

Salt content of crudes (Maximum in PTB)

25

25

Where PTB is pounds per thousand barrels)


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7.

Effluent Quality ( from ETPP )

Oil content of water effluent from ETPP (ppm vol.)

8.

Zakum

Umm Shaif

< 200

< 200

Water Removal Rates from Gas / Oil Separators and Spheroids The rate at which the produced water will be removed at any particular stage is uncertain, but the overall removal rate is expected to be greater than the equivalent of 10% of peak crude production rate. Thus, the overall water removal rates are:

HP & LP separators and spheroids actual (10% of crude) (BPD)

Zakum

Umm Shaif

37,800

29,500

Total Rates (actual)

67,300

Maximum rate at which water can be removed from each separator stage is as follows (i.e. design bases on earlier higher production rates): HP Separators (BPD)

33,000

39,000

LP Separators (BPD)

33,000

39,000

66,000

78,000

33,000

39,000

Total from Separators Spheroids (BPD) Overall Total (Design) (BPD)


216,000

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B)

PRINCIPLES OF PROCESS

Desalting is a hot water extraction process. The salt or salt solution in a crude oil is diluted by adding wash water and then thoroughly mixing. In practice, the mixing stage can approach 100% efficiency and then the salt content of the desalted crude is dependent upon the amount of dilute solution left, and is given by the formula: Salt content of desalted crude (in PTB)

= Salinity of water in desalted crude (lbs/bbl) x 1000 x 3 1–x3

Where : Note:

x 3 is water cut fraction (vol. %) in desalted crude.

To convert the PTB (Pound per Thousand Barrel) salt content of desalted crude to ppm, use the conversion: 1 PTB =

approximately 3.436 ppm (part salt per million part net crude of 52 ib/ft3)

After mixing, the crude / salt /water mixture enters the desalter where separation occurs. This separation is assisted by temperature, an electric field and / or demulsifier chemicals.


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C)

PRINCIPLES OF OPERATIONS Dehydration & Desalting System

1.

Desalting Process The desalting process consists of two basic steps: Dehydration & Desalting. The first step reduces remnant water in oil to at least 0.2%. In the second step, a fresher water dilutant is injected to lower the average salt content to an acceptable level. Additional dehydration reduces remnant water content to 0.1% and the salt content in the crude to 25 pounds per thousands (25 PTB).

2.

Dehydration The first step in the process is water removal. Through agitation, an emulsion is created by dispersion of the water in droplet form. It is held in this state by emulsifying agent in crude oil. These agents are generally resins, asphalt, organic acids and solids which are produced with the oil. They are attracted to the surface of the water droplets and help from a tough film around them, isolating each water droplet from the other. This film must be weakened or broken before coalescence can take place. Chemical aids, demulsifiers and heat are used to break the emulsion. By increasing the oil temperature, dispersion of the emulsion is more rapid and complete. Oil density and viscosity are decreased for more rapid gravitational settling of the water droplets. The final part of the dehydration phase involves coalescing small droplets into larger ones so that gravity separation can take place. Both the dehydrator and the desalter use the same principle of electrostatic coalescence of the water droplets to separate the salty water from the crude oil.


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3.

Electrical The electrostatic coalescence process may be explained as follows:

4.

+

-

-

Water molecules is neutral, but its composition is a dipole (H OH ), under electric field the Dipole State is induced.

-

A droplet of water suspended in oil assumes a perfectly spherical shape if there are no external force acting upon it.

-

Once a high voltage field is applied, the droplet distorts into an elliptical shape by the positive charges (+) in the droplet being pulled to the side nearest the negative electrode and the negative charges (-) are pulled to the positive charge.

-

The result is a rapid pulsation, which aids the demulsifier in destroying the film of emulsifying agent.

-

This coupled with polarized attraction of the separate droplets stimulates coalescence and when the water droplets are heavy enough they fall to the bottom of the vessel.

-

The force field is generated from a high voltage transformer (3.3 kv1) connected to the internal grid plates.

-

Pairs of electrode plates are charged in opposition “positive and negative charge”.

-

Water droplets entering the field between the electrode plates are elongated and attracted to one or the other, as the droplets approach the plates they accept the charge of the one closest to them and are repelled towards the plat of opposite charge, the process is self repeating.

Dilution Water Injection Wash water (De-Oxygenated seawater) is supplied to the plant via a main 8” water line from the Sea Water Oxygen Removal Plant (SWORP). After entering the plant, the water flow rate is measured and transmitted to the control room and if the rate is very low, a low flow switch activates a shutdown valve on the water supply and initiates an alarm. Before the wash water can be sued in the process, it must be heated to approximately 100 deg. F. Two steam heat exchangers (one spare) have been provided for water heating.


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The wash water temperature is controlled by an indicator / controller in the Zakum Control Room. After heating, the water is distributed throughout the plant via the main 8” supply header and the following branches: -

Dilution Water As well as the injection before the desalter mixing valves, provision is made for injection before the dehydrator mixing valves.

-

Sand Jet Water Some wash water is used intermittently for desanding operations on the vessels. The emulsion treater, desander, desalters, and dehydrators are provided with internal sand / sludge jetting nozzles which are used to wash solids out of the vessels.

-

Miscellaneous A small amount of water is used by the oil in water monitor for sample dilution and by the oxygen / combustible gas analyzer on the CHF heater for sample cooling.


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5.

Recycle Water System After the mixture dilution water / crude oil enters the desalter, the water and oil are separated. The water is heavier than oil and it is collected at the bottom of the desalter and must be removed. The water which is collected in the desalter is used by the process and is pumped (recycled) from the desalter for injection into the oil just ahead of the dehydrator. The water / oil interface level in the desalter is controlled by an external displacer (cage) type level instrument and as the water level in the vessel varies up or down, the water flow rate out of the vessel is increased or decreased to maintain the constant interface level. A mechanical position switch on the level control valve trips the pump motor and accordingly prevents the recycle water pump from operating when the valve is nearly closed. If the dehydrator vessel is by-passed, recycle water may be disposed to the Effluent Water Header and then to the SWDP.


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D)

CHEMICAL INJECTION:

Two vessels have been provided for site storage of oil demulsifier chemicals. The chemicals are pumped to the tanks from offsite through two chemical supply lines. There is a separate supply line for each storage vessel. The outlet of each chemical tank is led to a manifold which can supply chemical to the suction of 16 chemical injection pumps. Two pumps (one spare) are provided for each desalter train and the emulsion treater. Each pump is capable of taking suction from either chemical storage tank or a calibration pot. A ½” chemical injection line for each train runs from the pump outlet to an injection point on the 12” crude oil line just ahead of the flow valves. The chemical injection rate should be changed when ever the crude oil rate is changes so that a constant ratio is maintained.


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Purpose Of The Crude Oil Chemcial Injection Facilities

Chemicals are required for injection into oil in the Dehydration and Desalting scheme as follows: Demulsifier to promote the separation of water from the oil phase. Corrosion inhibitor to protect the internal surfaces of pipeline and equipment. Scale inhibitor to prevent the precipitation of the scale products in water. Bulk chemical storage facilities are provided for four streams which are: Umm Shaif Umm Shaif

Demulsifier Corrosion Inhibitor

Zakum Zakum

Demulsifier Corrosion Inhibitor


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N.B. For Sea Water Oxygen Removal Plant, the following chemicals are injected for the following purpose: Chemical Injection:

-

Oxygen Scavenger Agent: A catalysed sulfite chemical is injected as a liquid into the oxygen removal towers, in order to reduce the residual oxygen i.e. commercially zero.

-

Scale Inhibitor: To overcome the problems of scale formation in both the towers and the treated water system, it is necessary to continuously inject an inhibitor into the sea water. Anti Foam Agent: An anti foam agent is added to the line of the oxygen removal towers. The anti foam agent controls the foam formation rather than eliminating it completely.

-

Organic Biocide: Organic biocide will be injected intermittently. This maintains sterile conditions and prevents the growth of sulfate reducing bacteria’s (SRB’s).

-

Polyelectrolyte: Required as a filter aid for the sea water filters. The chemical is injected downstream of the booster pump.


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E.

-

MAIN CONTROL LOOPS

After injection of the recycle water, the crude oil and water are mixed by flowing through a pressure differential valve PDV. The pressure drop across the valve causes the oil and water to mix and the amount of pressure drop can by adjusting the local mounted PDIC [by experience the pressure should be about 15 psig].

-

The oil / water interface level is controlled by LC which signals LV and LAH, LAL.

-

If the pressure build up occur PAH will alarm at 175 psig & PSV will lift at 350 psig.


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Crude Oil Dehydration and Desalting

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