Review of Demulsification mechanism of Water in Crude oil emulsion and “Bottle Testing” procedure

Part 1Chandran Udumbasseri* Technical Consultant

Abstract:

Crude oil emulsion breaking is necessary to remove water from oil phase. The emulsifying agent that is causing

formation of interfacial film between water and oil can be fractured by changing volume fraction of phases,

temperature, salinity, pH, etc. Rondon’s17 mechanism of demulsification explains the changing of HLB value by

varying concentration and nature of the surfactant which causes phase inversion and thus emulsion breaking.

Winsor30 postulated balancing the energy of interaction of surfactant with water and energy of interaction of

surfactant with oil which promotes emulsion breaking. Goldzsal3 experimentally found that optimum

demulsification could be achieved by using polymer resins with intermediate hydrophilicity. Aveyard 21 found

increased demulsification by increasing demulsifier up to “critical aggregate concentration” and beyond this micro

emulsions were formed with increase in demulsifier. Different crude oil “bottle testing” parameters were studied and

results summarized. Selection of solvents, dilution of demulsifier concentration for “bottle test” dosing, effect of pH

and salinity of aqueous layer, effect of silicone additives, wetting agents, corrosion inhibitor, viscosity depressants

on demulsifier performance, evaluation of demulsifiers with different chemistry, effect of crude temperature on the

performance of demulsifiers in winter and summer, measurement of conductivity to evaluate the performance of

demulsifier bases and their formulation and there by understand synergistic effect are described

Introduction:

The main problem in wet crude oil processing is water-in oil emulsion. This emulsion is broken by using chemicals

that can act at the interface of water and oil emulsion. This paper reviews the characteristic of emulsion and its

breaking. The selection of a demulsifier for a particular crude oil is done by conducting “bottle Test” of crude oil

using different demulsifier formulations. The information and conclusions from bottle tests are not usually available

in literature for reference. An attempt is made to study the effect of different parameters that can destabilize the

water-in oil emulsion.

Crude oil

Wet crude oil flowing from the drilling wells to the surface contains emulsions because of processing and mixing

that occur during well production operation. Water is present in most of the crude oil wells and sometimes water is

also injected as water or steam to enhance oil production. As the mixture passes through piping and valves the

mechanical actions cause dispersion of water in oil. The natural surfactant present in crude oil stabilizes these

emulsions. The indigenous materials such as asphaltenes, resin, naphthanates, inorganic materials, clay, dust, etc

present in oil get adsorbed at the interface between water and oil

*E-mail address: cudumbasseri@yahoo.co.in

It is necessary to separate water and oil as soon as the crude flows to the surface and pressure gets reduced.

Sometimes wet crude oil contains more than 90 % water. Water causes serious corrosion problem to crude oil

processing equipments because of the dissolved inorganic ions (mainly chloride) present in water. The crude oil is

separated to its useful range of components by fractionation in refineries where water is undesirable. So water

should be separated from crude oil before transporting or refining the wet crude oil.

Crude oil is a mixture of hydrocarbon compounds with varying physical and chemical characteristics from one

production field to another. The terms like, light, heavy, naphthenic, paraffinic, sweet and sour are used to

characterize crude oil based on boiling range, composition and sulfur content. The classification of crude oil fraction

is based on solubility each fraction, namely, saturates (heptane soluble), aromatics, resins and asphaltenes (SARA in

abbreviation).

Sulfur is present in the form of elemental sulfur, hydrogen sulfide, carbonyl sulfide and in organic form like thiols

and thiophenes. Crude contains oxygen containing compunds like furanes, phenols, esters and carboxylic acids

(naphthenic acids). Nitrogen is found in the form of amines, amides, pyrroles and pyridines in high boiling fraction

of the crude oil. Small amounts of metals like nickel, vanadium and iron are also present. Toxic elements mercury

and arsenic are found in very low concentration. Salts of sodium, magnesium and calcium as chloride, sulfate and

carbonates are present in produce water.

Table 1

Crude oil Classification based on density (kg/m3) (Klerk 200812).

Classification Density range (kg/m3)

Light crude <825

Medium crudes 825-875

Heavy crudes 875-1000

Extra heavy crudes >1000

SARA Distribution

A typical SARA distribution in crude oil is given below:

Table 2

Parameters West African

Crude

North Sea

Crude

Saudi Crude

(Sarbar and Wingrove 199823)

Problem wells Non-problem wells

Saturates, % 47.9 48 37.5 30.3

Aromatics, % 36.5 37.5 44.4 44.5

Resin, % 15.2 14.2 13.8 20.7

Asphaltene, % 0.4 0.3 4.3 4.5

Review of theories of emulsion breaking

Emulsion is dispersion of a liquid (dispersed phase) within another liquid (continuous phase). The emulsion stability

is conferred by the presence of materials at the interface of dispersed phase and continuous phase. These materials

delay the separation of the two types of liquids into two phases. These materials are having polar and non polar

active groups and are surface active agents. The size of dispersed water droplets is of 100 micron spherical diameter

and much larger compared to colloidal particles (1micron size). Emulsions of this size are thermodynamically

unstable while micro emulsions (10 – 50nm) are thermodynamically stable

The emulsion is classified into four, namely, stable, meso-stable, unstable and entrained water. Their spontaneous

demulsification time (under Laboratory conditions) is tabulated:

Table 4

Class Duration

Stable-actual emulsion >4 weeks

Meso stable < 3 days

Unstable Short time

Entrained water 1 day

Phase inversion

Emulsions are broken by creating a condition in which water and oil phases invert to each other and finally separate

and settle as pure phases. Water in oil emulsion can be inverted to oil in water emulsion by physical and chemical

process. The phase inversion can be achieved by changing volume fraction of phases, temperature, salinity, acid–

base character, etc. These factors affect the affinity of the surface active agent present at the interface of the two

phases. The surfactants have Hydrophilic-lipophilic-Balance (HLB) values which keep an emulsion stable. This

balance of values can be changed by varying the concentration and nature of emulsifying agent (Rondon 2008 16).

When volume fraction of dispersed phase of the emulsion increases the interface gets deformed. The distance

between droplets gets reduced and this droplet crowding causes change in flow character resulting in the inversion

of emulsion. Practically by increasing water cut of the crude oil inversion can be achieved. This type of phase

inversion is reported at 20-50% volume fraction.

Winsor (195430) has found that when the energy of interaction of surfactant with water is equal to energy of

interaction of surfactant with oil the emulsion separates quickly in to two phases (Winsor). This concept can be

expressed in an equation:

Winsor Ratio, R =

Where Aco = Net interaction energy of surfactant minus that of oil per interfacial unit area

Acw = Net interaction energy of surfactant minus that of water per interfacial unit area

When the value of R<1, the aqueous phase (with surfactant) is in equilibrium with pure organic phase. This system

favors o/w emulsion.

When the value of R>1, the organic phase is in equilibrium with water. This favors w/o emulsion

When the value of R = 1, the emulsion separates as pure organic layer and pure water layer.

So by changing the factors like, salinity of water, temperature, nature of surfactant, nature of oil, etc the balance of

interaction can be modified. Winsor’s Ratio is used to optimize the demulsification process.

Goldzal and Bourrel (20003) found profound correlation between emulsion stability and surfactant phase behavior.

Phenolic resins with increasing length of EO+PO head groups confer hydrophilicity to the resin. The affinity of

phenolic resin shifts from lipophilic to hydrophilic as EO + PO content increases. The work of Taylor (1992)27 on

nonylphenol formaldehyde resin ethoxylates with varying content of EO concluded that 5EO per phenol group of

the resin showed minimum water-in oil emulsion stability when treated

Goldzal and Bourrel concluded the following important points:

1. Phenolic resin with low EO+PO (that is having more of lipophilic nature) showed poor quality water

separation and low % water dropping

2. Phenolic resin with intermediate EO+PO ( that is balanced Hydrophilic- lipophilic nature) showed good

quality water separation and high % water dropping

3. Phenolic resin with high EO + PO (that is having high hydrophilic nature) showed poor quality water

separation even though % water dropping was high.

4. Optimum demulsifier performance showed by oxyalkylated resins having intermediate hydrophilicity

5. Cross linked polyurethane were not as effective as alkyl phenol formaldehyde resin in promoting

coalescence of water droplets

6. The decay in emulsion viscosity is faster in cross linked polyurethane as molecular weight increases. The

time needed to drop water considerably reduced as molecular weight of polyurethane goes high. As

molecular weight increases the number of polar groups also increases in the polymer molecule. These

molecules acts as flocculants and promote group sedimentation. They act as anchor in water-oil interface.

So a synergy of both resins in combination performs well in reducing the time for complete water

separation.

Aveyard et al ( 2003)21 showed that polyethoxylated surfactant with EO (9-10) can separate water-in oil emulsion

and the water separated was having slight color and low viscosity. Higher EO (12-13) causes high colored and

viscous water layer due to aggregated surfactant and solubilized oil. Lower EO monomer species partitioned

predominantly to the oil phase and high EO members to aqueous phase.

Aveyard concluded the following:

1. Indigenous surfactants present in crude oil are weakly adsorbed. So high degree of displacement by added

demulsifier is expected.

2. Increase in demulsification with increasing demulsifier concentration up to “critical aggregate

concentration” (cac) is rationalized with increasing displacement of indigenous surfactant by demulsifier

which is unable to stabilize the emulsion droplets.

3. The fastest rate of emulsion resolution is expected when there is zero energy barrier to droplet growth and

the process is completely controlled by diffusion.

4. Increasing the demulsifier concentration (overdosing) beyond “cac” causes micro emulsions of oil-in water

if the surfactant is hydrophilic and water in oil micro emulsion if the surfactant is hydrophobic.

Randon, et al (2008)17 postulated the principle of dehydration process to explain emulsion stability and its breaking.

When HLB of surfactant is varied the w/o emulsion approach a minimum stability state as the surfactant gets

adsorbed at the interface and exhibits the same affinity for water and oil phase. So it is important that the surfactant

should attain equal affinity for both phases. The natural surfactant is more lipophilic and the added demulsifier is

more hydrophilic. As the added demulsifier penetrates to the interface and continuously change the interfacial

system from lipophilic towards hydrophilic and a balancing state attains and the emulsion breaks quickly. The more

hydrophilic the demulsifier the lesser was its requirement. In practice, a compromise of not too much hydrophilic

and nor of low concentration of demulsifier is required. The experiments concluded a threshold asphaltene

concentration at which the interface is saturated. Beyond this critical value the demulsifier concentration is constant

for quick emulsion braking.

1. For quick emulsion breaking the lipophilicity of natural surfactant and hydrophilicity of added demulsifier

surfactant should balance to approach equal affinity for both phases.

2. Beyond some critical asphaltene concentration the requirement for demulsifier for quick emulsion remains

the same. This varies for each crude oil as the asphaltene content varies.

The most important points from the above research works can be summarized as:

1. The indigenous surfactant in crude oil is weakly adsorbed to the emulsion interface.

2. An intermediate EO + PO head group addition to phenolic resin favors optimized demulsification with

good water dropping (Goldsal)

3. High molecular weight polyurethanes reduce water separating time. Higher molecular weight adds more

polar groups to the polymer molecule. These polar groups’ acts as anchors in water oil interface and

flocculate and promote group sedimentation.

4. Emulsion resolution is fast when there is zero energy barrier which help droplet growth. This is simply a

diffusion process (Aveyard).

5. Overdozing cause micro emulsion in water for hydrophilic surfactant and micro emulsion in oil layer if the

surfactant is hydrophobic.

6. Quick emulsion break is achieved by balancing lipophilicity and hydrophilicity at the interface of w/o

emulsion (Randon).

It appears from these conclusions that points 2(Goldsal), 4(Aveyard) and 6(Randon) are identical with different

concept of parameter evaluation.

Summary: Emulsion stability and Emulsion breaking

1. Common factors affecting emulsion stability

1.1. The emulsion stability will increase with pH decrease. Water-in oil is unstable in pH range from 5 to

12 (Strassner, 196825, Ramalho 200910).

1.2. Solids give higher viscosity to emulsion. Solid particles/wax, etc, stabilize the emulsion. The solid

particles get wet by the two liquids, oil and water in the emulsion. They serve as mechanical barrier

to prevent coalescence of the droplets (Langevin 200413, El Sharkawy1,Sullivan 20025, Ali 20004)

1.3. Formation of surfactant film around droplets facilitates emulsification. The formation of interfacial

film reduce requirement of agitation energy (it is necessary to agitate the oil-water mixture at high

speed to make the emulsion. But presence of emulsifying agent reduces the requirement of agitation

energy) (Baumgardner 20067).

1.4. Viscosity is related to the stability of emulsion. Higher the viscosity more is the emulsion stability

(Alvarez 20096).

1.5. Asphaltene, wax and clay contribute to the stability of w/o emulsion

1.6. The emulsion from fresh crude is unstable but when exposed to light the emulsion become more

stable (Ronningsen 199522).

1.7. Polar compounds such as nickel porphyrins present in sufficient amount promote emulsion formation

(Porphyrins are present in crude oil. Porphyrins are naturally occurring organic compounds.

Chlorophyll is magnesium porphyrin. Hemoglobin is iron porphyrin) (Lee 199914)

1.8. Influence of density- if the density of crude oil is high the emulsion will be more stable.

1.9. Salt concentration- emulsions with fresh water is more stable. The emulsion with high salt content is

less stable. So sea water is used for the flushing out oil from the pores of the sediment rocks in the

drilled oil wells.

1.10. Aging causes increased emulsion stability. It causes oxidation, photolysis, evaporation of light ends

and bacterial action (Hanapi 20068 ,Helen 199715, Maclean 199711)

1.11. Presence of Iron oxide (corrosion products), calcium carbonate (scaling products), etc, causes more

stability to the emulsion (El Sharkawy1, Sullivan 20025)

1.12. The melting and re-crystallization of wax cause stabilization of emulsion. When melting point is

exceeded, the wax goes back to oil from the interface and their action at the interface gets reduced.

While at low temperature the wax crystallizes and contributes to the stabilization of emulsion.

2. Common factors affecting emulsion breaking.

2.1. Increasing the temperature above paraffin melting point 50-60oC can destabilize the emulsion. Wax

and paraffin melt out and disappear from the interface at higher temperature and destabilize the

emulsion. (Grace 199220)

2.2. In addition to demulsifier, solvents that can reduce viscosity can improve the demulsification.

Solvents like Xylene and isopropyl alcohol that keep demulsfiers in soluble state also reduce the

viscosity of the medium.

2.3. The stability of emulsion can be reduced or destroyed with increasing water percentage. High amount

of water in the emulsion can give large droplets that can be easily flocculated and separated from the

oil layer.

2.4. Influence of density- if the difference in density between water and oil is more, then separation is

better. Light crude emulsions can be broken easily.

2.5. Corrosion inhibitor – presence of CI reduce the amount of iron sulfide (solid material that stabilize

the emulsion) and help demulsification. Corrosion inhibitors combine with iron sulfide and dissolve

them. They are removed from the interface and emulsion stability is reduced.

2.6. If asphaltene is removed (asphaltene can be removed by passing the oil through silica filled column)

then oil cannot form w/o emulsion. Asphaltene is one of the compounds that contribute to the

stability of the emulsion. If they are removed from interface film then the emulsion stability gets

reduced.

2.7. Addition of salt to water - addition of salt increases the chances of emulsion breaking. At fixed

asphaltene concentration, an increase in salinity generally leads to a lower demulsifier requirement

(Kokal 200526)

2.8. Paraffin crystal modifiers reduce the emulsion stability. If the paraffin modifiers are added to the

crude oil they reduce the crystallization point of the paraffin at low temperatures. So the wax crystals

are not formed.

2.9. Neutralization of emulsifying agent- emulsion can be destabilized by neutralizing polar charges

associated with the emulsifying agent. The electric double layer that exists between emulsion droplets

carries charges, both positive and negative charges. These charges stabilize droplets from coming

close for agglomeration. So if demulsifier contains charge neutralizers, then it is easy to break

emulsion and aggregate the droplets by coalescence.

2.10. Iron sulfide, salt, clay, mud solid, paraffin, etc complicate the demulsification. It can be disposed in

oil phase or water-wetted (combination of sludge conditioner and wetting agent) and removed with

water. Sludge conditioners like acrylates can remove the solid particles from the interface and

destabilize the emulsion. Wetting agents wet the solid particles that stabilize the emulsion. Then they

can be removed through water or oil layer.

2.11. In water/oil emulsions, the most effective demulsifiers are oil soluble or hydrophobic. This is because

the oil is the continuous phase and water is the dispersed phase. The surfactant will get absorbed into

the continuous phase without any resistance.

2.12. Demulsifier products with surfactants of varying amount of hydrophilic groups are having a strong

tendency to invert water -in-oil emulsions to oil-in-water emulsion. So they have the ability to revert

the w/o emulsion to two separate phases. Such demulsifier products are most effective.(Goldszal3)

2.13. Demulsifier with branched structure showed better and fast water dropping compared to star and

linear structure.(Ramalho 201010)

2.14. The best demulsifiers are the one that can reduce the interfacial shear viscosity, increase the

interfacial mobility and destabilize the water-in-oil emulsion (Sjobolom 200319).

2.15. Pressure inside the separating vessel (three phase) usually has less effect on the emulsion stability.

The interfacial tension is reduced when the pressure is reduced.

2.16. To ensure high quality performance, a demulsifier should posses the following characteristics:

2.16.1. The demulsifier should be able to partition into the water phase (this may be achieved through

Vander Waals forces, hydrogen bonding, etc.).

2.16.2. The demulsifier should dissolve in the oil phase

2.16.3. The concentration of the demulsifier in the droplet must be sufficient to ensure a high enough

diffusion flux to the interface (demulsifier should have certain solubility in the water layer

also)

2.16.4. The interfacial activity of the demulsifier must be high enough to suppress the interfacial

tension gradient (this is achieved through Vander Waals forces), thus accelerating the rate of

film drainage and hence promoting coalescence

Experimental Details

During the crude oil bottle testing a set of demulsifier bases are screened to find out the bases that perform well as

good water dropper, desalter, deoiler, etc. The next step will be to formulate selected bases to get the final

formulation. The following steps are involved in the initial preparation of demulsifier bases, conducting screening of

bases and final formulation.

1. Selecting solvents for diluting bases for dosing

2. Deciding the base dilution concentration for dosing

3. Selecting the temperature at which the performance evaluation has to be conducted.

4. Deciding the duration up to which the performance has to be evaluated (water dropping, water quality,

interface quality, desalting, unresolved emulsion, etc)

5. Classifying the best performing bases based on chemical structures, RSNs, cost, etc.

6. Formulating the selected bases, screening and selecting the best performing formulations and final ratio test

with the incumbent demulsifier.

As the procedure for crude oil bottle testing is a universal one, the variations are bound to occur with each petroleum

technician’s decision according to the nature of crude oil, available testing facility, duration allowed for testing by

the customer, available human power with the testing team, and the ability of the team to find a suitable formulation

in short period of testing.

“Bottle Testing” Procedure

Sample collection: The crude oil samples were collected directly from Saudi Aramco gas oil separating plants and

used for conducting the experiments. The samples were refrigerated to 5-6oC and used in the subsequent day after

bringing the crude oil sample to ambient temperature:

Procedure:

a. The water bath was heated up to the required temperature and maintained (this temperature corresponds to

the temperature at the production header at the particular plant).

b. 100 mls of the crude oil was transferred to graduated demulsifier glass tube with conical bottom

c. The demulsifier was dosed at required ppm level and tightened caps.

d. Placed all the filled tubes on the wooden shaker and given 100 shakes.

e. Placed the tubes in the constant temperature water bath. Noted the initial time to start the observation

f. Noted the water dropping at the specified interval. Continued this up to the required time interval

g. Carried out the measurement of other parameters like, water and interface quality, top oil water cut,

unresolved emulsion, salt measurements, etc.

1. Selecting solvent for dilution: Solvents like, aromatic hydrocarbons, alcohols, heavy aromatics, solvent

naphtha, etc are used for formulating the demulsifier. It was found that the selection of the solvent is very important

to enhance the performance of a demulsifier formulation.

McLean and Kilpatrick 199711 conducted tests to gauze the power of solvent aromaticity on emulsion stability by

using aromatic solvents with varying molecular structure. It was evident that all the tested solvents were very

effective in destabilizing the emulsion and some of them resolved the emulsion. It was also found that as the

molecular weight of the aromatic solvent increases greater destabilization effect was observed. The following graph

(1) shows the influence of different solvents on the performance of a single Demulsifier

Graph-1

The above graph is the plot of water dropping (volume) against time interval for the following demulsifier samples

1. D1 in Xylene: Demulsifier formulated in Xylene solvent

2. D1 in HA: Demulsifier formulated in Heavy Aromatic solvent

3. D1 in HA+SN (80/20): Demulsifier formulated in a mixture of Heavy Aromatic solvent + Solvent Naphtha

at 80:20 ratio

4. D1 in IPA: Demulsifier formulated in Iso Propanol

5. D1 in Butanol: Demulsifier formulated in N-Butanol

6. D1 in Octanol: Demulsifier formulated in Octanol

The results show that alcohols with high methyl groups are better solvents for this crude oil. The demulsifier used

for this test was a polyol and this must have favored for alcohol solvent over aromatic solvents. Also heavy aromatic

solvent (HA) and Xylene are good solvents. Solvent selection is based more on price and local availability.

2. Deciding the base dilution concentration for dosing: Usually diluted demulsifier solutions are dosed to

get better results from the test. The dilution is decided after conducting the tests. The dilution can be from 1%, 5%,

10%, 20%, 50%, etc. Once the dilution level is decided this dilution should be followed for all tests conducted.

Otherwise unrelated results are observed. This can be understood from the following set of results.

Graph-2

In the above graph (2) water dropping by demulsifier dissolved in different solvents and at different concentrations

is plotted. G150, G200, C150 and C200 are heavy aromatic naphtha of different grades. The plot reveals the

following:

1. 1% dilution is showing better performance especially solvent G200

2. The performance decreases 1%> 5%>10%

3. G200 is heavy aromatic solvent with Carbon above 12.

So during bottle testing it would be better to prepare 1% dilute demulsifier solution in heavy aromatic solvent,

provided the price of solvent is acceptable.

4. pH of wet crude oil water phase: Kokal (2005)26 explained the effect of pH of water phase on the

emulsion stability. Adding inorganic acids and bases cause the ionization of asphaltene end groups, organic acids

and bases that are present at the interface. Low pH favors w/o emulsion while higher pH favors o/w emulsion.

Optimum pH for demulsification is approximately 10 in certain crude oils.

Experiment with Saudi crude oil showed water dropping increased from pH 8 onwards when the water pH was

adjusted. pH adjustment increased water dropping up to 80% (includes free water). Organic acid and amine base

were used for pH adjustment. Organic acid and base are soluble in oil and water phase. Water separated was

estimated by straight centrifuging after 24 hours or by 50% dilution with Xylene which gave more accurate results.

The results are plotted in the graph (3) which shows a sudden increase in water dropping from pH 8 onwards.

Graph-3

5. Effect of water phase Salinity: Increasing the salinity of emulsified water can promote better emulsion

breaking (Fortuny 200718). A definite amount of salt was added to the crude and conducted the test. Better results

were obtained by coupling demulsifier dosage and salinity increase. Increased salt concentration in the water phase

favor lower demulsifier dosage for increased water dropping. The graph (4) shows plot of water dropping at

different demulsifier concentration and salinity.

Graph-4

Injecting sea water with high salinity can help emulsion breaking and thereby cause reduction in the demulsifier

consumption.

6. Demulsifier Performance Evaluation: It is necessary to evaluate each available demulsifier bases and

find out the best bases that can be used for final demulsifier formulation. The following table shows the results of

different types of demulsifier bases screened on Saudi medium density crude oil (specific gravity, 0.879 at 60 oF) at a

temperature (production header) of 45oC. The results conclude the following:

1. Initial fast water dropper (D3, D5, D10) gave residual salt in the crude oil which was above (40, 11,

15PTB) the limit value of 8 PTB

2. Poor water droppers like D6 (maximum water dropping at 45 minute = 18%) showed very low salt in crude

oil (2.1 PTB) and low top oil moisture (0.01%)

3. There are demulsifiers (D7; water dropping = 89%; salt in crude = 3 PTB) which gave good result as water

dropper and salt remover from crude oil. But showed low initial water dropping.

Table 4

Crude Type = Medium Saudi

Total Water Cut = 56%Dosage = 35 ppm;

Water Bath Temperature = 45oC;

Retention Time = 45 Minutes

S/N Demulsifier Bases Water Dropping, % / minutesTop oil

dryness,

Salt in

Crude,Interface

0 15 30 45 % PTB

1 D3 -Oxyalky Phenolic Resin 0 23.21 29.46 33.93 0.8 40 Fair

3 D5 -Polymeric Polyol 0 41.07 57.14 75 0.1 10.8 Good

4 D6 -Amine Alkoxylate 0 0 0.54 17.85 0.01 2.1 Fair

5 D7 -Polyol 0 8.93 35.71 89.29 0.05 3 Fair

7 D9 -Imine Alkoxylate 0 30.36 71.43 92.86 0.05 2.3 Good

8 D10-Polymeric Polyol 0 25 42.86 53.57 0.04 15 Good

During emulsion breaking once the outside interfacial film is broken the water droplets are free to drop down or

agglomerate to form large droplets and settle down under gravity pull because of difference in density of water and

crude oil. Agglomeration takes place when flocculants are also present to collect the smaller water droplets to make

larger ones. This is the situation with demulsifiers like D7. But demulsifiers like D3 & D5 help agglomeration of

much larger sized water droplet and settle down quickly while they fail to collect smaller droplets which hang on in

the oil phase. These droplets also carry ions present in water giving more residual salt in crude oil. Demulsifiers like

D6 although broken all emulsions as seen from the low top oil water cut, does not have flocculants that can collect

small freed water droplets and help to form larger droplets that can settle under gravity. If the demulsifiers D3, D5,

etc are combined with D6 the result will be good water dropping coupled with reduction in salt in oil phase. Section

8 gives good examples of synergic effect of such combination.

The following chart (Graph 5) shows probable demulsifiers with their chemistry that find application in Saudi Crude

oil in Gawar area. The chemistry is as given by the product suppliers. The main applicable demulsifiers are polyols,

amine (PEI) ethoxylate and NPF ethoxylates as shown in the chart.

Graph 5

7. Effect of Additives on demulsifier performance: Saxena et al (2009)24 conducted experiments using

polyorganosilixane demulsifiers (Momentive products) as additives to organic demulsifiers to enhance the

performance of organic demulsifiers. Tests were conducted using silicone demulsifier additives to improve the

performance of organic demulsifiers. Silicone demulsifiers were supplied by Momentive Performance Materials.

Silicone demulsifiers used was 2% of the organic demulsifier dosage. The graph (6) shows plot of water dropping

(%) at different intervals by the combination of demulsifier D11 and different silicone demulsifier additives.

Graph 6

The results shows that the water dropping efficiency of demulsifier D11 improved by 30% (D11+2% S329) in the

initial 15 minutes and 20% at 45 minutes. The crude oil with specific gravity 0.879 at 60 oF (API 29.5) was used for

the test.

Figure 1

The figure 1shows the effect of silicone demulsifier additive on water and interface quality, the bottle with mark “B”

is without silicone additive and bottle with mark “A” is with silicone additive. Organic demulsifier with 2% silicone

additive gave clear water layer with sharp interface.

8. Effect of Wetting agents and Slug treatment additives : Addition of slug treaters in demulsifier

formulations impart better oil-water interface quality by digesting the slug accumulated at the interface. Slug may

the deformed remains of natural surfactant, inorganic material that was accumulated at the emulsion interface or

insoluble organic matter. These slugs can be removed to oil or water layer by using wetting agents. Addition of

wetting agent (Witconic Acid from Akzo Nobel) to demulsifier formulation improved interface sharpness as can be

seen from the Figure 2 (bottle with mark “D” is without wetting agent and bottle with mark “C” is with wetting

agent. The graph (7) shows plot of water dropping (%) and salt in crude oil (PTB) against the wetting agent

concentration in the demulsifier formulation, DF2.

Graph 7

The plot of wetting agent composition against salt in crude oil shows considerable reduction in the salt content in

crude oil with increase of % wetting agent in the demulsifier formulation. Wetting agent wets the slug at the

interface and removes the materials to oil or water layer. Figure 2 shown below shows hanging oil layer in Bottle

“D”and it disappears in bottle “C” where wetting agent was added.

Figure 2

9. Effect of Corrosion Inhibitors: The light crude oil used for test was having specific gravity 0.787 (API

gravity = 48.3) at 60oF. The emulsion in light crude oil was usually unstable and easily broken once pressure was

reduced. Most of the water separated in a short time and interface contained slug and corrosion products. During

bottle testing, the salt content in oil layer reduced to a minimum value and then increased at a low rate as the

demulsifier (DF3) dosage was increased. When corrosion inhibitor (oil soluble amine based) as dosed the

concentration of salt in oil layer reduced with increase of inhibitor dosage. The graph is a plot of chemical dosage

against salt content in the crude oil. The salt content in crude oil was low (10 PTB).

10. Effect of viscosity depreesent on demulsifier performance at low temperature: Williams et al (2009)29

studied the application of aliphatic anhydrides as demulsifiers at low temperature. These additives function as

viscosity depressents at low temperatures. The graph given below shows the depreesion in the viscosity of a

demulsifier formulation at lower temperature (plot F1+1% Ac2 and F1+5% Ac2)

Bottle tests were conducted using acetic anhydride as viscosity depression additive and compared to understand the

effect this type of additive on water dropping. But this anydride can also function as demulsifier. The water

dropping (%) is ploted against chemical dosage.

The plot shows increase in water dropping (%) when 5% Additive is added to the demulsifier formulation.

11. Performance of Demulsifier and Crude oil Temperature: It was found during bottle testing that

demulsifiers that dropped water better in winter did not show the same performance in summer season and vice

versa. Some demulsifiers are designed by the manufacturer to perform better in winter and some in summer.

Practically it is not possible to change demulsifier between winter and summer where both winter and summer goes

to their extreme level. This makes the formulator a difficult situation. The following graph (6) shows water dropping

by demulsifier D11. The plot at a temperature of 26oC shows the performance in winter season while plots at 46oC

and 48oC show the performance in summer season. D11 shows water dropping more than 80% in winter while it

shows varied water dropping in summer, between 20 and 25%.

Graph-6

The plots at 46oC and 48oC appear wave like which means that some emulsification is also taking place during

demulsification. The asphaltene- wax solubilizers present in the demulsifier helps to keep the crystallized material

away from the interface during winter while the same may be functioning as emulsifier during summer season.

12. Measurement of conductivity and emulsion breaking: It was suggested by Van Dijk and Oschman28 that

performance of demulsifiers can be evaluated using conductivity. Water in oil emulsion is a trap of dissolved ions in

water of the emulsion which is not having the ability to conduct. Conductivity probe consists of two electrode

separated by a distance 1cm. A constant voltage is applied between the electrodes. Electric current flows through

water due to this voltage and is proportional to the amount of ions present in water - the more the ions, the more

conductive the water.

So when the emulsion starts breaking the water in the emulsion is freed with the ions in it which is measured by the

conductivity. As more and more emulsion breaks the conductivity goes on increasing until conductivity value

stabilizes. If there is any re-emulsification then the conductivity goes down again.

Experiment: The crude oil sample taken in a glass beaker was cooled to a lower temperature. The sample stirred by

magnetic rod and heated on a temperature controlled heating device like hot plate. The conductivity probe and

temperature sensor were placed in the stirred oil sample. Demulsifier was dosed. Temperature was increased slowly

and noted conductivity at different temperatures. A graph was plotted for each demulsifier used. Tests were

conducted for each demulsifier used separately.

The graph (7) given below is a plot of conductivity against temperature for a demulsifier formulation and its

components for crude oil-1 (specific gravity 0.879 at 60oF; API 29.5)

Graph-7

The plot for component-2, shows the emulsion breaking started from 10oC onwards and went on increasing and

stabilzed above 40oC. The plot for component-1 and 3 show starting of emulsion breaking from 40 oC onwards. As

the conductivity of all the three components are below 100uS/cm, it shows that still some water droplets are not

completely broken. The plot for formulation-DF, shows the sudden emulsion breaking at 32 oC and continued upto a

temperature of 52oC.

1. Emulsion breaking and water droplet flocculation started from temperature 32oC onwards.

2. The droplet size increased with droplet merging upto the temperature 52 oC. This is shown by the sudden

increase in conductivity

3. At the temperature 52 oC the merged droplets started settling in to a separate layer and got removed from

the bulk of oil. This is shown by the decrease in conductivity at 52 oC

4. After one hour settling the oil layer showed a conductivity of 0.08uS/cm. Water separated as clear bottom

layer

This is a good exam,ple of synergysm caused by correct type of component selection and formulation.

Graph 8 shows the conductivity vs temperature plot for Demulsifier formulation DF2 and its components 1 & 2 for

crude oil-2 (specific gravity 0.884 at 60oF; API 28.6)

Graph-8

The plot for DF2 Formulation shows increase in conductivity from temperature 19oC to 32oC. the conductivty

started dropping from this temparature with separation of water layer.

13. Relation between pH, Water dropping, Salt content and RSN for Demulsifier Bases with same chemistry

Demulsifier bases of same chemistry with different RSN (Relative Solubility Number) values were tested on the same crude oil under the same conditions of testing. RSN value was correlated with water dropping from crude and salt reduction of the crude oil phase. The test results are given below:

S/N Demulsifier ID

Chemistry RSN pH(1% in IPA/water:70/30)

Salt content, uS/cm

Water dropping, %

1 Base 1 PEI Alkoxylated 13.5 5.8 78.7 162 Base 2 PEI Alkoxylated 8.3 11.64 2.49 903 Base 3 PEI Alkoxylated 6.7 6.4 3.4 0

1. As per previous conclusion on RSN, as RSN increases the water dropping increase for bases with same chemistry. So base (1) with RSN 13.5 should drop more water compared to bases 2 &3. But it is dropping less water compared to Base 2.

2. Apart from RSN, if the pH is considered then, Base 1 has pH 5.8 and Base 2 has pH 11.64(alkaline range). It is a general rule that higher the pH value more the emulsion breaking. The high pH value of base 2 helped it to drop water; also it may have some flocculating effect.

3. Comparing Base 2 with 3, pH value of Base 3 is 6.7(neutral range), less than that of Base 2 (11.64). Base 3 is not dropping water at all.

4. Base 2 &3 have very low salt content almost comparably same. Here applying the rule, lower the RSN value, lower the salt content, the salt content of base 3 should be less than that of base 2. But Base 2 has lower salt content of the two. Now applying the rule, that complete salt reduction of oil layer is possible only after complete emulsion breaking, it can be concluded that complete emulsion breaking had occurred for both Bases 2 &3. But the flocculation of the freed water occurred efficiently in the case of Base 2 while it did not occur in the case of Base 3.

5. The main difference between Base 2 and 3 is the pH value, being higher in the case of Base 2. This helped water droplet flocculation and dropping in the case of Base 2.

Conclusion;

Taking in to account all previous observations, for Bases with same chemistry:1. Higher RSN value cause higher water dropping 2. Low RSN value help low salt content in crude oil layer 3. High pH value of Base helps better water coalescence or dropping

Conclusion

All the experiments were conducted using Saudi medium density Crude oil. Results can be summarized as follows:

1. Selection of solvents: Heavy aromatic solvents showed good enhancement of demulsifier performance.

Alcohols with higher number of methyl groups showed better enhancement.

2. Dilution of Demulsifier for dosing during bottle testing: 1% dilution with appropriate solvent gave good

results. Dilution should followed during the whole testing program

3. Effect of water phase pH: Water dropping is accelerated if the aqueous layer pH is adjusted above 8.

4. Effect of water phase salinity: increasing salinity of water layer accelerates water dropping. Use of more

saline water for well injection can help reduced demulsifier dosage.

5. Effect of silicone additives on demulsifier performance: addition of 2% silicone demulsifier additives to

organic demulsifier improves water dropping, water clarity and interface sharpness.

6. Effect of wetting agents on demulsifier performance: addition of wetting agent cause disappearance of

interface slug accompanied by increase in water dropping and considerable reduction in salt content of oil

layer.

7. Effect of Amine based Corrosion inhibitor: Corrosion inhibitor showed good desalting of light crude oils

8. Effect of viscosity depressants: Acetic anhydride reduced the viscosity of demulsifier at temperature range

above 5oC. Addition of 1% to 5% of acetic anhydride increased water dropping capability of demulsifier.

9. Demulsifier performance based on different chemistry: demulsifiers having flocculating ability showed

good water dropping ability. But they did not show good salt reduction in crude oil. Salt reduction is based

on the demulsifier chemistry. Amine ethoxylates were found good salt reducers for crude oils used in the

tests.

10. Effect of climatic variation on demulsifier performance: Some demulsifiers were found good water

droppers during winter season and poor performers during summer and vice versa. This could be attributed

to the presence of additives in the demulsifier bases.

11. Measurement of conductivity to evaluate demulsifier performance: conductivity measurement was found a

good tool to understand the performance of individual bases and the final formulations. The synergism

caused by the combination could be fully understood by this method.

AcknowledgementI hereby acknowledge Mr.Abboud Smadi, CEO, and Mr. Ziad Katabi, General Manager of REDA for allowing me to conduct all the experiments. My special thanks go to Mr. Shuaib Ellias and Ahmed Sadah for conducting the experiments as I planned. I am indebted to Mr.Ahmad Mira and Taher for arranging all required samples from Saudi Aramco Gas Oil Separating Plants. Above all we are grateful to Saudi Aramco personnel for allowing us to collect crude oil samples as and when required. We acknowledge Momentive Performance Materials for supplying silicone demulsifiers and Akzo Nobel for wetting agents that were used for performance evaluation

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