Emulsion Wax of Heavy Crude

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Anne Silset

Emulsions (w/o and o/w) of HeavyCrude Oils.Characterization, Stabilization,

Destabilization and ProducedWater Quality

Thesis for the degree of philosophiae doctor

Trondheim, November 2008

Norwegian University of

Science and Technology

Faculty of Natural Science and Technology

Department of Chemical Engineering



NTNU

Norwegian University of Science and Technology

Thesis for the degree of philosophiae doctor

Faculty of Natural Science and Technology

Department of Chemical Engineering

©Anne Silset

ISBN 978-82-471-1270-0 (printed ver.)

ISBN 978-82-471-1272-4 (electronic ver.)

ISSN 1503-8181

Doctoral Theses at NTNU, 2008:285

Printed by Tapir Uttrykk



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Paper 1

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!d5 bK Z-00*68+-6T %66- ?*5+-,T %614-9+ Z966*+195T L3)96 ?MN/530

Journal of Dispersion Science and Technology, 26(5), 615-628, 2005

Paper 2

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Journal of Dispersion Science and Technology, (2007), 28(4), 639-652

Paper 3

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Paper 4

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Accepted in Energy & Fuels

Paper 5

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Journal of Dispersion Science and Technology, 26(6), 665-672, 2005

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Journal of Dispersion Science and Technology, 29 (1), 139-146, 2008

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1

CONTENTS

1. INTRODUCTION TO CRUDE OIL AND PETROLEUM PROCESSING......................... 3

1.1 History.............................................................................................................................. 31.2 Origin ............................................................................................................................... 41.3 Crude oil ........................................................................................................................... 61.4 Recovery........................................................................................................................... 71.5 Transportation ..................................................................................................................91.6 Refining.......................................................................................................................... 101.7 Challenges ...................................................................................................................... 12

1.7.1 Wax ......................................................................................................................... 131.7.2 Asphaltenes ............................................................................................................. 141.7.3 Naphthenate............................................................................................................. 15

References ............................................................................................................................ 18

2. HEAVY CRUDE OILS AND EMULSION STABILITY .................................................. 202.1 Heavy crude oils ............................................................................................................. 202.2 SARA ............................................................................................................................. 212.3 Emulsions and stabilizing mechanisms..........................................................................242.4 Emulsion resolution in electrostatic processes and separation facilities........................ 28References ............................................................................................................................ 34

3. THE PRODUCED WATER ISSUE ....................................................................................363.1 The origin of produced water ......................................................................................... 363.2 The composition of produced water ............................................................................... 373.3 Impact of produced water on the environment............................................................... 403.4 Treatment of produced water .........................................................................................42

3.4.1 Conventional technologies for water teatment........................................................ 423.4.2 Produced water management .................................................................................. 453.4.3 Recent produced water treatment developments.....................................................47

References ............................................................................................................................ 50

4. MULTIVARIATE DATA ANALYSIS............................................................................... 514.1 Principal Component Analysis (PCA) ........................................................................... 514.2 Outlier detection.............................................................................................................52

References ............................................................................................................................ 54

5. EXPERIMENTAL TECHNIQUES.....................................................................................555.1 Critical Electric Field (Ecritical) .................................................................................... 555.2 Rheometry ...................................................................................................................... 575.3 Nuclear Magnetic Resonance (NMR) ............................................................................ 59

5.3.1 Introduction to the principle of NMR ..................................................................... 595.3.2 Determination of droplet size via NMR.................................................................. 62

5.4 Turbiscan analysis .......................................................................................................... 645.5 Coulter Counter method ................................................................................................. 65References ............................................................................................................................ 67



2

6. MAIN RESULTS................................................................................................................. 68Paper 1.................................................................................................................................. 68Paper 2.................................................................................................................................. 70Paper 3.................................................................................................................................. 72Paper 4.................................................................................................................................. 74

Paper 5.................................................................................................................................. 76

7. CONCLUDING REMARKS ............................................................................................... 79



3

1. INTRODUCTION TO CRUDE OIL AND PETROLEUM

PROCESSING

1.1 History

The oil history began over five thousand years ago. In the Middle East, oil seeping up through

the ground was used in waterproofing boats and baskets, in paints, lighting and even for

medication [1]. The modern petroleum history began in the later years of the 1850s with the

discovery, in 1857, and subsequent commercialization of petroleum in Pennesylvania in 1859

[2]. The first oil well structures in open waters were built in the Gulf of Mexico. They were

construced from a piled jacket formation, in which a framed template had piles driven through

it to pin the structure to the sea bed at water depths of up to 100 m. A support frame was

added for the working parts of the rig such as the deck and accommodation. These structures

were the fore-runners for the massive platforms that now stand in very deep water and in

many locations around the world. There have been land oil wells in Europe since 1920s. It

was not until the 1960s the exploration in the North Sea really begun, without success in the

early years. They finally struck oil in 1969 and have been discovering new fields ever since.

The subsequent development of the North Sea is one of the greatest investment projects in the

world [1].

Petroleum is the most important substance consumed in modern society. It provides not only

raw materials for the ubiquitous plastics and other products, but also fuel for energy, industry,

heating, and transportation. The word petroleum, derived from the Latin petra and oleum,

means literally rock oil and and refers to hydrocarbons that occur widely in the sedimentaryrocks in the form of gases, liquids, semisolids, or solids. From a chemical standpoint,

petroleum is an extremely complex mixture of hydrocarbon compounds, usually with minor

amounts of nitrogen-, oxygen-, and sulfur-containing compounds as well as trace amounts of

metal-containing compounds [3].

The fuels that are derived from petroleum supply more than half of the world’s total supply of

energy. Gasoline, kerosene, and diesel oil provide fuel for automobiles, tractors, trucks,

aircraft, and ships. Fuel oil and natural gas are used to heat homes and commercial buildings,



4

as well as to generate electricity. Petroleum products are the basic materials used for the

manufacture or synthetic fibers for clothing and in plastics, paints, fertilizers, incecticides,

soaps, and syntetic rubber. The use of petroluem as a source of raw material in manufacturing

is central to the functioning of modern industry [3]. Figure 1.1 shows the distribution of

proved reserves of crude oil in 2007. Proved reserves of oil are generally taken to be those

quantities that geological and engineering information indicates with reasonable certainty can

be recovered in the future from known reservoirs under existing economic and geological

conditions [4].

Figure 1.1: Colour coded map of the world and associated bar chart, showing proved oil reserves at end 2007 in

thousand million barrels. The Middle East has the greatest proved oil reserves at 755.3 thousand million barrels.

This is followed by Europe and Eurasia, with 143.7 thousand million barrels, Africa (117.5), South and Central

America (111.2), North America (69.3) and finally Asia Pacific with 40.8 thousand million barrels [4].

1.2 Origin

Two schools of thought exist about the origin of petroleum: an Estern school suggesting that

its origin is biogenic resulting from the decay of organic biological matter and stored in

sedimentary basins near the Earth’s surface, and a Ukrainian-Russian school proposing that is

is abiogenic with inorganic origin deep within the Earth’s crust dating back to the creation of

Earth [5, 6]. The two theories have been intensely debated since the 1860s, shortly after the



5

discovery of widespread occurrence of petroleum. The idea of abiogenic petroleum origin

proposes that large amounts of carbon exist naturally in the planet, some in the form of

hydrocarbons. Hydrocarbons are less dense than aqueous pore fluids, and migrate upward

through deep fracture networks. From the idea of biogenetic origin petroleum is a naturally

occuring hydrocarbon mixture, but hydrocarbons that are synthesizied by living organisms

usually account for less than 20% of the petroleum [7]. The remainder of the hydrocarbons in

petroleum is produced by a variety of processes generally referred to as diagenesis,

catagenesis, and metagenesis. These three processes are a combination of bacteriogical action

and low-temperature reactions that convert the source material into petroleum. During these

processes, migration of the liquid products from the source sediment to the reservoir rock may

also occur. The biogenic origin of petroleum is a mainstream theory adopted by the majority

of petroleum reservoir engineers, geologists and scientists. It is supported by field

observations, laboratory experiments and basin models used to explain known economic

occurrence of natural gas, crude oil and asphalt [3].

Hydrocarbons and their associated impurities occur in rock formations that are usually buried

thousands of feet below the surface. These reservoir rocks must possess fluid-holding capacity

(porosity) and also fluid-transmitting capacity (permeability). A variety of different types of

openings in rocks are responsible for these properties in reservoir rocks (figure 1.2).

Petroleum migrates to a pool or field, displacing the water, in which the oil or gas occupies

pore space in the rock. A hydrocarbon reservoir has a distinctive shape, or configuretion, that

prevents the escape of hydrocarbons that migrate into it.

Figure 1.2: The figure shows pores as small open spaces on the left hand side and connected pores that give

good rock permeability on the right hand side [8].

These reservoir shapes, or traps, can be classified into two types: structural traps and

stratigraphic traps. Structural traps form because of a deformation in the rock layer that

contains the hydrocarbons. Two examples of structural traps are fault traps and anticlinical



6

traps (figure 1.3). Strategic traps form when other beds seal a reservoir bed or when the

permeability changes within the reservoir bed itself [3, 8].

Figure 1.3: Two typical petroleum traps: fault trap and anticline trap. The lightest compounds (gas) is on the top,

while oil, and water if present, is found further down in the formation leading to gas, oil and water zones [8].

1.3 Crude oil

Crude oil is the name given to all organic compounds which are liquid under reservoir

conditions. They can partly solidify at the surface after expansion and cooling [9, 10]. Crude

oil is not a uniform material with a simple molecular formula. It is a complex mixture of

gaseous, liquid, and solid hydrocarbon compounds, occuring in sedimentary rock deposits

throughout the world. The composition of the mixture depends on its location. Two adjacent

wells may produce quite different crudes and even within a well the composition may vary

significantly with depth. Neverthless, the elemental composition of crude oil varies over a

rather narrow range [11]:

C 83.0-87.0 wt.% O 0.05-1.5 wt.%

H 10.0-14.0 wt.% S 0.05-6.0 wt.%

N 0.1-2.0 wt.% Metals <0.01 wt.%



7

Although at first sight these variations seem small, but the various crude oils are extremely

different. The high fraction of C and H suggests that crude oil consists of hydrocarbons,

which indeed has been proven to be the case. From detailed analysis it appears that crude oil

contains alkanes, cycloalkanes (naphthenes), aromatics, polycyclic aromatics, sulfur-

containing compounds, nitrogen-containing compounds, oxygen-containing compounds, etc.

The larger part of crude oil consists of alkanes, cycloalkanes, and aromatics. Both linear and

branced alkanes are present. In gasoline applications the linear alkanes are much less valuable

than the branched alkanes, whereas in diesel fuel the linear alkanes are desirable.

Cycloalkanes are often called naphthenes. Aromatics have favorable properties for the

gasoline pool. However, currently their adverse health effects are receiving increasing

attention. The most important binuclear aromatic is naphtalene. The heavier the crude the

more polycyclic aromatic compounds it contains. Heavy crudes render less useful products.

The amount of sulfur may at first sight seem low. However, its presence in petroleum

fractions has many consequences for the processing of these fractions. The presence of sulfur

is highly undesirable, because it leads to corrosion, poisons catalysts, and is environmentally

harmful. The nitrogen content of crude oil is lower than the sulfur content. Nervertheless,

nitrogen compounds deserve attention because they disturb major catalytic processes. The

oxygen content of crude oil is usually low, and oxygen occurs in many different compounds.

A distinction can be made between acidic and non-acidic compounds. Organic acids and

phenols belong to the class of acids. Metals are present in crude oil only in small amounts.

Even so, their occurrence is of considerable interest, because they deposit on and thus

deactivate catalysts for upgrading and converting oil products. Part of the metals is present in

the water phase of crude oil emulsions and may be removed by physical techniques. The other

part is presented in oil-soluble organometallic compounds and can only be removed by

catalytic processes. Most of the metal-containing compounds are present in the heavy residue

of the crude oil. The metal contents vary widely and the most abundant metals are nickel,

iron, and vanadium [11].

1.4 Recovery

The first stage in extraction of crude oil is to drill a well into the underground reservoir. Often

many wells are drilled into the same reservoir, to ensure that the extraction rate is

economically viable (figure 1.4). In addition, some wells (secondary wells) may be used to



8

pump water, steam, acids or various gas mixtures into the reservoir to raise or maintain the

reservoir pressure, and so maintain an economic extraction rate. If the underground pressure

in the oil reservoir is sufficient, the oil will be forced to the surface under this pressure

(primary recovery). Natural gas is often present, which also supplies needed underground

pressure (primary recovery). In this situation, it is sufficient to place an arrangement of valves

(the Christmas tree) on the well head to connect the well to a pipeline network for storage and

processing. Over the lifetime of the well the pressure will fall, and at some point there will be

insufficient underground pressure to force the oil to the surface. Secondary oil recovery uses

various techniques to aid in recovering oil from depleted or low-pressure reservoirs.

Sometimes pumps, such as beam pumps and electrical submersible pumps are used to brung

the oil to the surface. Other secondary recovery techniques increase the reservoir pressure by

water injection, natural gas reinjection and gas lift, which inject air, carbon dioxide, or some

other gas into the reservoir [3].

Figure 1.4: The oil and gas are found in so called reservoir rock, sealed by a non-penetrable cap. The lightest

compounds (gas) is on top, while oil, and water if present, is found further down in the formation leading to gas,

oil and water zones [12].

Enhanced oil recovery (EOR, tertiary oil recovery) relies on methods that reduce the viscosity

of the oil to increase. Tertiary recovery is started when secondary oil recovery techniques are

no longer enough to sustain production. For example, thermally enhanced oil recovery

methods are those in which the oil is heated, making it easier to extract; usually steam is used

for heating the oil. The viscosity (or the API gravity) of petroleum is an important factor that

must be taken into account when heavy oil is recovered from a reservoir. In fact, certain



9

reservoir types, such as those with very viscous crude oils and some low-permeability

carbonate (limestone, dolomite, or chert) reservoirs, respond poorly to conventional secondary

recovery techniques. A significant amount of laboratory research and field testing has been

devoted to developing enhanced oil recovery methods as well as defining the requirements for

a successful recovery and the limitations of the various methods [3]. The quality of the well

product and separation of oil and water will be discussed more in detail in chapter 2.

1.5 Transportation

Most oil fields are at a considerable distance from the refineries that convert crude oil into

usable products, and therefore the oil must be transported in pipelines and tankers (figure 1.5).This gives possibilities for changes in temperature, pressure and composition during

transportation. Flow assurance of the multiphase system is of therefore of great importance,

both from an economical and environmental point of view.

Figure 1.5: Figure to the left shows typical tiebacks from wellhead to the platform. For successful transport of

produced fluids knowledge about “flow assurance” is important [13]. Figure to the right shows oil pipeline in

Saudi Arabia [14].

However, most crude oils need some form of treatment near the reservoir before it can be

carried considerable distances through the pipelines or in tankers. Fluids produced from a well

are seldom pure crude oil. In fact, the oil often contains quantities of gas, saltwater, or even

sand. Separation must be achieved before transportation. Separation and cleaning usually take

place at a central facility that collects the oil produced from several wells. Another step that

needs to be taken in the preparation of crude oil for transportation is the removal of excessive



10

quatities of water. Crude oil at the wellhead usually contains emulsified water in proportions

that may reach 80% to 90%. It is generally required that crude oil to be transported by

pipeline contain substantially less water than may appear in the crude at the wellhaed. In fact,

water contents from 0.5% to 2.0% have been spacified as the maximum tolerable amount in a

crude oil to be moved by pipeline. It is therefore necessary to remove the excess water from

the crude oil before transportation [3, 15-17].

Flow assurance (the successful transportation of produced fluids in long pipelines in a harsh

environment) is a major hurdle for technical and economic success in deep water. The

challenge is to move the produced oil, gas, and water from wells located at the bottom of the

sea floor to platforms located in more shallow water. The fluids are subjected to cold ocean

temperatures and large pressure changes that may cause them to be unstable and thereby

create problems (figure 1.6) [13].

Figure 1.6: The figure illustrates expensive production problems caused by fluid chemistry during production of

crude oil [13].

1.6 Refining

Crude oil is rarely used in its raw form but must be processed into its various products,

generally as a means of forming petroleum products with hydrogen content different from that

of the original feedstock such as gasoline, diesel fuel, asphalt base, heating oil, kerosene, and

liquefied petroleum gas. Crude oil is separated into fractions by fractional distillation. The

fractions at the top of the fractionating column have lower boiling points than the fractions at



11

the bottom. The heavy bottom fractions are often cracked into lighter, more useful products.

All of the fractions are processed further in other refining units (figure 1.7) [3, 11].

Figure 1.7: Representation of a destillation tower showning many of a refinerys many important processes [18].

Each refinery has its own range of preferred crude oil feedstock from which a desired

distribution of products obtained. Figure 1.8 shows the relative placement of different

processes within the refinery. According to Speight [3], refinery processes can be divided into

three major types:

Separation: divison of crude oil into various streams (or fractions) depending on the nature

of the crude material.Conversion: production of saleable materials from crude oil, usually by skeletal alteration, or

even by alteration of the chemical type of the crude oil constituents.

Finishing: purification of various product streams by a variety of processes that accomplish

molecular alteration, such as reforming.



12

Figure 1.8: Flow scheme of the relative placement of unit operations in a refinery [3].

1.7 Challenges

The problems encountered in production of petroleum are highly dependent on the properties

of the processed fluids and the reservoir rock. In some parts of the world, operators face

challenges due to high wax content, in other parts due to asphaltenes, sulfur, co-produced



13

reservoir material etc. Problems can be found in all stages of operation. Problems can be due

to rheological properties of the fluids, deposition and plugging, erosion, corrosion, catalyst

poisoning, emulsion formation etc.

Precipitation and/or deposition of organic or inorganic material at pipe walls, in reservoirs or

in equipment like heat exchangers, hydrocyclones etc can cause serious problems with respect

to flow conditions and efficiency of the process. Type of solids encountered during petroleum

production can be: waxes, asphaltenes, hydrates, diamondoids, scales, calcium naphthenate,

sulfur, and many more. The temperature in deep water, usually near 40°F (4.4°C), can create

flow problems in risers and export pipelines. In the next sections problems related to wax,

asphaltenes and naphthenates are discussed in more detail.

1.7.1 Wax

Wax deposition in pipelines and risers is an ongoing challenge to operators, and can have a

significant effect on oil production efficiency. Build-up in pipelines can cause increased

pressure drops, resulting in reduced throughput and thus reduced revenue. In more extreme

cases, pipelines/processing facilities can plug, halting production and leading to potentiallyhuge losses in earnings.

The wax present in petroleum crudes primarily consists of paraffin hydrocarbons (C18 - C36)

known as paraffin wax and naphthenic hydrocarbons (C30 - C60). Hydrocarbon components

of wax can exist in various states of matter (gas, liquid or solid) depending on their

temperature and pressure. When the wax freezes it forms crystals, and crystals from paraffin

wax are known as macrocrystalline wax. Those formed from naphthenes are known as

microcrystalline wax. As the clean waxy crude flows through a cold pipe or conduit (with a

wall temperature below the cloud point of the crude) crystals of wax may be formed on the

wall. Wax crystals could then grow in size until the whole inner wall is covered with the

possibility of encapsulating oil inside the wax layers. As the wax thickness increases, pressure

drop across the pipe needs to be increased to maintain a constant flow rate. As a result, the

power requirement for the crude transport will increase. The arterial blockage problems of

clean waxy crude can be efficiently controlled by insulation and heating of the pipe to a

temperature above its cloud point. Most of the existing wax deposition problems of the clean



14

waxy crudes are due to the lack of proper insulation and heating systems. As a result

application of chemical anti-foulants and frequent use of pigging operation have become

necessary. Regular paraffinic or waxy crudes are widespread in the world and the major

complex systems problems related to the production, processing, and transportation of these

medium-gravity fluids is not just crystallization of their wax content at low temperatures, but

the formation of deposits which do not disappear upon heating and will not be completely

removed by pigging (figure 1.9) [3, 9, 10, 19, 20].

Figure 1.9: Pigging to remove wax from a subsea transfer line. Pigging devices fit the diameter of the pipe and

scrape the pipe wall as they are pumped through the pipe [20].

1.7.2 Asphaltenes

Some crude oils contain large amounts of asphaltenes, which can destabilize due to large

pressure drops, temperature changes, shear (turbulent flow), solution carbon dioxide (CO 2 ) or

other changes in oil composition. Asphaltene deposition can present a major flow assurance

challenge. Deposition can occur in various parts of the production system including well

tubing, surface flow lines and even near the wellbore (figure 1.10). Crude oils that are

susceptible to pressure-induced asphaltene precipitation are generally highly undersaturated;

that is, the subsurface formation pressure is much higher than the bubble point. The crude oil

can experience a large pressure drop without evolving gas. Once gas evolves, the light alkane

fraction of the liquid phase is reduced, thus increasing the solvating power of the oil, thereby

stabilizing asphaltenes.



15

Figure 1.10: Asphaltene deposition in a pipeline [20].

Particles, even in small amounts, can also cause huge problems for separation of water-in-oil

emulsions as they gradually concentrate in the interfacial layer in separators. Speight [3] has

viewed the effect of asphaltenes and resin constituents on recovery and refining processes.

Asphaltene deposition and fouling of flowlines/facilities can greatly reduce productivity and

increase operational costs through the requirement for frequent chemical treatment and

removal of deposits [3, 9, 10, 20, 21].

1.7.3 Naphthenate

Deposition of metal naphthenates in process facilities is from an operational point of view one

of the most serious issues related to the production of acidic crudes. The problem arises from

pressure drop and degassing of carbon dioxide during the transport of the fluids from the

reservoir to the topside, leading to dissociation of naphthenic acids at the interface between

the crude and the co-produced water. Consequently, the naphthenic acids may react withmetal cations in the water to form naphthenates. These electrochemically neutral compounds

might then start to agglomerate in the oil phase, normally in combination with inorganic

materials, and further adhere and accumulate to process unit surfaces. This may lead to costly

shutdown periods during which the deposits have to be removed. Metal naphthenate

deposition in topside facilities is becoming a common problem in a number of fields where

acidic crudes are being processed. Calsium naphthenate deposits in a separator are illustrated

in figure 1.11 [9, 10, 22-28].



16

Figure 1.11: Calcium naphthenate build-up in separator [29].

StatoilHydro researchers and operational staff have worked intensively with chemical

suppliers to find ways of preventing and treating the problem. For many years, the accepted

view was that calcium naphthenate deposition resulted from a reaction between natural

naphthenic acids in the oil and calcium ions in the formation water. This still holds true. But

nobody was able to identify which naphthenic acids are active in the process, quantify them,

and unravel their elusive molecular structure. However, in the summer of 2002

ConocoPhillips and StatoilHydro made a decisive breakthrough from a study of advanced

analytical data. Although initially confidential, both partners have now agreed to publish their

findings. The crucial revelation hinges on the identification of a new family of naphthenic

acids with molecular weights three times higher (1227 to 1235 g/mol) than the average

molecular weight of naphthenic acids in crude oil (430 g/mol). The ARN acid family (as it is

called) is also unique in the sense that the acids are four-protonic, whereas the other acids

encountered in Heidrun crudes (which constitute over 99.99 per cent of the total) are mono-

protonic [23]. The structure of ARN was refined by Ugelstad Laboratory in 2006 (figure 1.12)

[30].



17

Figure 1.12: The structure of ARN (C80 tetraacids) responsible for naphthenate deposition problems refined by

Ugelstad Laboratory in 2006 [30].



18

References

1. www.rigjobs.co.uk.2. Bell, H.S., American Refining, Van Nostrand, 1945.3. Speight, J.G. The Chemistry and Technology of Petroleum. 2007. 4.4. www.bp.com.5. Kenney, J., Kutcherov, V., Shnyukov, A., Krayushkin , V., Karpov, I., Plotnikova, I.,

Energia, 2001. 22(3): p. 26-34.6. Kenney, J., Kutcherov, V., Bendeliani, N., Alekseev, V., Proc. Nalt Acad Sci USA.

2002. 99: p. 10976-10981.7. Hunt, J., Petroleum Geochemistry and Geology. 1996. 2.8. www.argyleenergyinc.com.9. Chemistry, K.-O.U.E.o.I., Petroleum Technology, ed. I.a. II. 2007: John Wiley &

Sons.

10. Kirk-Othmer, Petroleum Technology. Ullmanns Encyclopedia of Industrial Chemistry,ed. I.a. II. 2007: John Wiley & Sons.11. Moulijn, J.A., Makkee, M., Van Diepen, A., Chemical Process Technology. 2001:

John Wiley & Sons Ltd.12. www.ems.psu.edu.13. http://www.peer.caltech.edu/basin_model.htm.14. http://original.britannica.com/.15. Gateau, P., Henaut, L., Barre, L, Argillier, J.F., Oil and Gas Science and Technology-

Rev. 2004. IFP 59: p. 503.16. Nomura, M., Rahimi, P.M., Koseoglu, O.R., Heavy Hydrocarbon Resources:

Charaterization, upgrading, and utilization. 2005, Washington D.C.: American

Chemical Society.17. Saniere, A., Henaut, I., Argillier, J.F., Brucy, F, Bouchard, R., Oil and Gas

Technology-Rev. 2004. IFP 59: p. 455.18. http://www.levininstitute.org/.19. Makogon, T.Y., Johnson, T.L., Angel, K.F. The 4th International Conference on

Petroleum Phase Behaviour and Fouling. 2003. Trondheim.20. www.hydrafact.com.21. Mullins, O.C. SPE Annual Technical Conference ans Exhibition. 2005. Dallas, Texas,

USA.22. Ubbels, S.J., Turner, M. The 6th International Conference on Petroleum Phase

Behaviour and Fouling2005. Amsterdam.

23. www.statoilhydro.com.24. Babaian-Kibala, E., Craig, H. L., Rusk, G. L., Blanchard, K. V., Rose, T. J., Uehlein,

B. L., and R.C. Quinter, and Summers, M. A. Naphthenic acid corrosion in refinerysettings, MaterPerformance. 1993. 32: p. 50-55.

25. Dyer, S.J., Graham, G. M., and Arnott, C. Naphthenate scale formation - examinationof molecular controls in idealised systems. In SPE 5th International Symposium onOilfield Scale, SPE 803952003. Aberdeen, UK.

26. Piehl, R.L., Naphthenic acid corrosion in crude distillation units. 1988. 27: p. 37-43.27. Rousseau, G., Zhou, H., Hurtevent, C. Aberdeen. Calcium carbonate and naphthenate

mixed scale in deep-offshore fields. In SPE Oilfield Scale Symposium SPE68307.2001. Aberdeen, UK.

28. Slavcheva, E., Shone, B., and Turnbull, A., Review of naphthenic acid corrosion in oilrefining. British Corrosion Journal. 1999. 34: p. 125-131.



19

29. Mediaas, H., Grande, K.V., Vindstad, J.E., Efficient Management of CalciumNaphthenate DepositionCalcium Naphthenate Depositionat Oil Fieldsat Oil Fields.TEKNA – Separation Technology. 2007.

30. Lutnaes, B.F., Brandal, Ø., Sjöblom, J., Krane, J. Organic and BiomolecularChemistry 2006. 4: p. 616.



20

2. HEAVY CRUDE OILS AND EMULSION STABILITY

2.1 Heavy crude oils

Crude oils are often divided into conventional crude oils, heavy crude oils, and extra heavy

crude oils. Specific gravity (SG) has been, since the early years of the industry, the principal

specification of crude oil products [1]. The American Petroleum Institute (API) gravity is of

more common use (figure 2.1). It refers to density at 60˚F (15.6˚C) and its relationship with

specific gravity is given by:

˚API = (141.5/SG)-131.5 (2.1)

Figure 2.1: Classification of petroleum by ˚API gravity and viscosity [1].

The hydrocarbon value hierarchy is shown as a graph of monetary value versus American

Institute of Petroleum (API) gravity (figure 2.2). Note that high ˚API values characterise light

hydrogen-rich deposits, while low ˚API cover heavy, carbon-rich deposits such as heavy oil.

These range from carbon-rich deposits, such as coal and heavy oil, to hydrogen-rich

accumulations like natural gas and natural gas liquids (NGL) [2-4].



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References

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3.2 The composition of produced water

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3.3 Impact of produced water on the environment

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41

dilution that takes place following discharge. Numerous variables determine the actual

impacts of produced water discharge. These include the physical and chemical properties of

the constituents, temperature, content of dissolved organic material, humic acids, presence of

other organic contaminants, and internal factors such as metabolism, fat content, reproductive

state, and feeding behavior [2, 10].

In the year 2000 produced water totaled about 150 million m3 and approximately 3500 metric

tons of oil was discharged to the sea [11]. Discharges will increase in the years ahead,

primarily because of increased water production from the major fields, and because the use of

chemicals is greater in fields with seabed completions. Each year, the Norwegian Petroleum

Directorate prepares short-term and long-term forecasts for production, costs, investments,

and discharges and emissions. These are based on data obtained from the operators. Measures

to reduce the discharges have been inadequate to reverse the trend of an increasing discharge

of produced water, which is mainly a consequence of more and more of the production taking

place from old fields where production of water increases. The measures have, however,

helped to reduce the discharge of oil per produced unit of water (Figure 3.3) [12].

Figure 3.3: Forecast of water production and discharge on the Norwegian continental shelf [3, 12].

The quantity of produced water in figure 3.3 that is not discharged to sea is re-injected into

the reservoir or to another formation suitable for disposal. The long-term effects of such

contaminants on the environment are not fully documented and understood. Some researchprogrammes are completed and several new studies are underway to map possible



42

consequences for living organisms. Dilution aspects and movement of species in the oceans

makes definite conclusions hard to make. There are so many variables that the modelling is

extremely complex. Results from recent research show however that fish exposed to alkyl

phenols have disturbances in both organs and fertility. These results are serious and have

triggered further investigations [3].

A common legislation for produced water discharges to sea from offshore installations has

been 40 mg/l (ppm) oil-in-water. The Oslo Paris Convention (OSPAR) has agreed that the

maximum discharge limit is reduced to 30 ppm oil-in-water for the petroleum companies

operating in the North-East Atlantic and that the overall oil discharges in produced water are

reduced by 15% from 1999 levels. In Norway, the oil operators have agreed to implement a

policy of zero harmful discharge within 2005. There shall be no harmful discharges from any

new installation, and existing installations shall continuously work against a practically

achievable zero harmful discharge [13].

In Norway the Pollution Control Authority (SFT) together with The Norwegian Oil Industries

Association (OLF) has developed a produced water management tool, the Environmental

Impact Factor (EIF), to meet the zero-discharge strategy. The EIF is a model for optimising

the activities taken to reduce the most harmful components in produced water for each

offshore installation. EIF considers all the contaminants in the produced water [3, 14-16].

3.4 Treatment of produced water

3.4.1 Conventional technologies for water teatment

During petroleum production, vast volumes of liquids have to be managed each day. Deferred

production causes high economical losses and therefore continuous operations are always

strived for. The capacity, reliability and performance of the produced water management

system is often critical for continuous oil production particularly in mature oil field where the

water production can greatly exceed the oil production. The water production system needs to

be designed to receive continuously increasing quantities of water as oil production continues.



43

Gravity based separation – flotation: Produced water treatment has traditionally taken place

in gravity based equipment, where the difference in the density of the two liquids to be

separated is utilized. Such separation is commonly performed in huge horizontal tanks at

different pressures. Flotation of the lighter components (oil) can be enhanced by means of

finely distributed gas bubbles going out of solution (pressure reduction) and parallel plate

packages installed diagonally in the separation vessel.

The EPCON Compact Flotation Unit (CFU) is a reliable and highly efficient technology for

separating water, oil and gas to achieve a high standard of treated water (figure 3.4). It

requires no external energy and the CFU also has a smaller volume and shorter retention time

than traditional flotation units currently in use. The EPCON CFU is a well-proven

environmental solution to treat the increasing volumes of produced water, and major operators

worldwide have tested and/or installed the technology [17].

Figure 3.4: A typical EPCON CFU installation working in parallel with a traditional water-treatment system to

increase total produced water treatment capacity [17].

Several combined processes, including gas flotation and induced centrifugal inertia forces, act

on the fluid components of different specific gravities. The small oil droplets are made to

agglomerate and coalesce, facilitating separation from the water. The separation process is

aided by internal devices in the chamber and a gas flotation effect caused by the release of



44

residual gas from the water. Process optimization can also be achieved by the introduction of

external gas and/or flocculants. The separated oil and gas is removed in a continual process

via an outlet pipe at the top of the vessel [17].

Separation techniques based on filtration: A well known technique for separating non

soluble components is by filtration. Several principles for handling produced water have been

considered including microfiltration membranes and media filters. Such treatment

technologies are potentially advantageous because of very good separation degrees can be

achieved. However microfiltration has found very limited practical application because of

cost and poor operability, very high energy consumption and degradation of the filters

elements with use.

Cyclonic separation methods: The continuous demand for higher treatment capacity in very

limited space has resulted in improved treatment methods. The most commonly used

technology in offshore production since around 1990 is the static hydrocyclone that utilizes

available pressure for enhanced speed in gravity separation (figure 3.5). The advantages for

this equipment type are high reliability (no moving parts), low maintenance, requires very

little space, and gives good separation effect and high capacity. Produced water is pumped

tangentially into the conical portion of the hydrocyclone. Water, the heavier fluid, spins to the

outside of the hydrocyclone and moves toward the lower outlet. The lighter oil remains in the

center of the hydrocyclone before being carried toward the upper outlet.

Figure 3.5: Schematic of hydrocyclone on the left hand side and multiple hydrocyclones inside a vessel on the

right hand side [18].



45

New challenges in handling produced water: Gravity based separation techniques have

together with static hydrocyclones been the most extensive method for treating produced

water. Other types of equipment have also been utilized, mostly in special cases with difficult

operating treatment characteristics or small volumes, though to a less extent. Even if produced

water systems more or less have functioned as intended with respect to the design

specifications, the future has brought new considerations regarding what is sufficient

treatment. A good alternative for disposal of produced water would be to send it back into the

reservoir where it came from as part of the pressure support, or to another suitable formation.

Unfortunately this requires extensive treatment prior to re-injection and due to high costs it is

an economically viable alternative mainly for fields with large water production. Reinjection

could also cause degradation of the reservoir production quality and productivity.

3.4.2 Produced water management

Based on the serious uncertainties connected to the long-term environmental effects from

produced water discharges and in order to be preventive of possible environmental damage

legislation is now being tightened. On the Norwegian continental shelf in the North-East

Atlantic, the government and the oil companies have agreed to zero harmful discharge inproduced water by the end of 2005. The petroleum industries operating in the area are

investigating several ways of meeting the new requirements.

Subsea separation: In order to reduce the necessary processing capacity in the petroleum

treatment plant, it could be advantageous to separate as much as possible of the water fraction

from the well stream at an early point in the production sequence. By placing first stage

water/oil separation process equipment on the sea bottom it will not be necessary to transport

all the water to the platform processing facility. The Platform facility is greatly simplified

with significant weight reduction. The water separated at the seabed can be injected into a

shallower well formation. Figure 3.6 presents a graphic illustration of the Troll Pilot subsea

installation in the Norwegian continental shelf.



46

Figure 3.6: The Troll pilot subsea unit [3].

Downhole technology: A further step in reducing the water-cut from the production stream is

to locate oil/water separation process equipment down in the production wells. This technique

has been investigated extensively the last years. The produced water is separated from the oil

and gas. It is then pressurised by downhole hydraulic pumps and re- injected into the

reservoir. The technology is still only in pilot design. It is still very expensive. The

complexity increases with reservoir depth. Vertical Downhole Oil/Water Separation (DOWS)

systems have been used to some extent world wide in the last years. A new more complex

horizontal separation system is under pilot testing pilot testing in Norway.

Water shut-off methods: In order to reduce the water flow to the well production zones,

there are two traditional methods utilized. During mechanical shut-off, cement or mechanical

devices blocks the water pathway by plugging the perforated production section. The

chemical shut-off includes injection of polymers into the reservoir that increases the water

viscosity, forms a stable gel and thereby restricts the water flow ability.

Sidetracking: An increase in water production for example as a consequence of water break-through in the production zone could be stopped by pulling the well internals, closing down

the perforated zone (mechanical shut-down) and drilling to a new section. Figure 3.7

illustrates several sidetrack wells drilled off from the old original.



47

Figure 3.7: Illustration of sidetrack weells [3].

3.4.3 Recent produced water treatment developments

As there is still no economically practically method for disposal of all the produced water via

re-injection or various recycle methods, a range of innovative wastewater technologies have

been developed or are under development. The different technologies all have their operating

characteristics that make them suitable for only certain produced waters or operating

characteristics. There is a major focus on new techniques to remove dissolved components

from produced water.

Separation by filtration: Utilization of membranes has been considered for treatment of oily

wastewater to reduce dissolved components. The new systems include the use of nano

filtration membranes. However, although the filtration method has very good separation

effect, the high costs and complexity of these treatment techniques means that applications are

only experimental.

Water treatment by extraction: Another technology that has been widely tested on both

pilot and full scale on the Norwegian continental shelf is rooted in the solvent properties of

supercritical liquids (CTour). The process utilizes liquid condensate (NGL) from the gas

scrubbers and injects it into the produced water upstream of the hydrocyclones. The dispersed



48

and dissolved hydrocarbons, which have higher solubility in the condensate, go into the

condensate phase and are separated in the hydrocyclones. This equipment has undergone

extensive pilot testing and its field tests are imminent. The process is very sensitive to the

available condensate quality.

Enhanced oil separation by means of coalescence: Several modern produced water

treatment methods are based on the coalescing of dispersed oil droplets, often prior to

cyclonic separation. The devices are installed upstream of the cyclonic vessels to increase oil

droplet diameters which will result in better separation degree in the hydro cyclones. The

process of coalescence could be accelerated by different means. One method is to install a

special fibre media in the pipelining or the hydrocyclone vessels that attracts oil droplets and

promotes coalescence into larger aggregates. These systems have no effect on removing

dissolved hydrocarbons, but are simple and easily retrofitted. The fibre media is sensitive to

fouling and any abrasive elements (sand) in the water. Other processes include combinations

of chemical injection (coagulation/flocculation) and mechanical agitation in specially built

vessels. Compact flotation units are hybrid cyclone/degassers that could replace standard

degasser equipment.

Methods based on adsorption: Adsorption has proven a successful area in maintaining

compliance with produced water discharges. Unfortunately most processes involve filters and

therefore are restricted in volume or require advanced regeneration processes which could be

both energy demanding and expensive. The adsorption techniques include activated carbon

filters with regeneration by wet air oxidation and oil-adsorbing media canisters based on

resins, polymer and clay technologies [3].

Many of the commercially available produced water treatment technologies are for dispersed

oil removal. Most of them are able to treat large water volumes from the oil fields with short

retention times. Hydrocyclones is today the most used technology on North Sea platforms.

Recent technological innovations in dispersed oil removal seem to have either concentrated

on increasing hydrocyclone removal efficiencies (coalescers, CTour) or developing more

compact and efficient flotation processes, for example, by combining flotation with cyclonic

separation. New types of filtration processes may also emerge (TORR). In dissolved

hydrocarbon treatment, there seem to be no good treatment alternatives available for produced

water treatment on oil platforms with large water flows. CTour is a promising technology and



49

removes the majority of the environmentally most harmful hydrocarbons. However, its

efficiency is not good for lighter hydrocarbons and requirements for the quality and quantity

of the condensate used in the process limits its general applicability. Many other methods that

are effective for dissolved hydrocarbon removal like adsorption and MPPE are judged to be

unsuitable (due to size, adsorbent disposal etc.) for treatment of large volumes of produced

water in offshore applications. Although membranes are now widely used in water and waste

water treatment (and other applications), the petroleum industry seems to be skeptical to the

process due to problems with fouling and regeneration (cleaning) in earlier field trials. It is a

challenge to develop a process for dissolved organics removal which is also compact enough

for use on offshore oil-fields. Biological treatment is judged to require too much space and

oxidation is hardly mentioned in overviews.



50

References

1. Amyx, J., D. Bass, and R.L. Whiting., Petroleum Reservoir Engineering, McGraw-

and N.Y. Hill Company, Petroleum Reservoir Engineering ed. N.Y. McGraw-HillCompany. 1960.

2. Veil, J.A., Puder, M.G., Elcock, D., Redweik Jr., A White Paper Describing

Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane

2004.

3. Nature Technology Solution, Introduction to Produced Water Treatment.

4. OGP, Fate and effects of naturally occuring substances in produced water on the

marine environment. no. 364, I.A.o.O.a.G.P. Report, Editor. 2005. p. 42s.

5. EPA, Development Document for Effluent Limitations Guidelines and New

Source Performance Standards for the Offshore Subcategory of the Oil and Gas

Extraction Point Source Category, EPA 821-R-93-003, U.S. Environmental Protection

Agency. 1993.6. Cline, J.T., Treatment and Discharge of Produced Water for Deep Offshore

Disposal, presented at the API Produced Water Management Technical Forum and

Exhibition, Lafayette, LA, Nov. 17-18, 1998.

7. Cline, J.T., Treatment and Discharge of Produced Water for Deep Offshore

Disposal, presented at the API Produced Water Management Technical Forum and

Exhibition, Lafayette, LA, Nov. 17-18. 1998.

8. Brendehaug, J., S. Johnsen, K.H. Bryne, A.L. Gjose, and T.H. Eide, Toxicity Testing

and Chemical Characterization of Produced Water – A Preliminary Study, in Produced

Water, J.P. Ray and F.R. Englehart (eds.), Plenum Press, New York. 1992.

9. Georgie W.J., D.S., and M.J. Baker, Establishing Best Practicable

Environmental Option Practice for Produced Water Management in the Gas and OilProduction Facilities, SPE 66545, presented at the SPE/EPA/DOE Exploration and

Environmental Conference, San Antonio, Feb. 2001.

10. Frost T.K., S.J., and T.I. Utvik, Environmental Effects of Produced Water Discharges

to the Marine Environment, OLF, Norway. (Available at

http://www.olf.no/static/en/rapporter/producedwater/summary.html.). 1998.

11. www.og21.org.

12. http://www.npd.no/Norsk/Frontpage.htm.

13. OSPAR, Annual report on discharges, wastes handling and air emissions from

offshore oil and gas installations, O.C. Report, Editor. 2004. p. 40p.

14. Utvik, T.R., Frost, T.K., Johnsen, S., OLF recommended guidelines - a manual for

standarised modelling and determination of the environmental impact factor (EIF.).

2003, Report for the Norwegian Oil Industry Association. p. 25p.

15. Johnsen, S., Frost, T., Hjelsvold, M., Utvik, T.R., The invironmental impact factor-a

proposed tool for produced water impact reduction, management and regulation. in

The SPE International Conference on Health, Safety and Environment in Oil and Gas

Exploration and Production. 2000. Stavanger, Norway.

16. Frost T.K., R., H., Regular discharges to sea-calculations for dispersion and

environmental risk. 2002, Statoil report F&T 200212100004. p.100p.

17. www.miswaco.com.

18. http://www.natcogroup.com/.



51

4. MULTIVARIATE DATA ANALYSIS

4.1 Principal Component Analysis (PCA)

Principal component analysis (PCA) is a projection method that helps researchers visualise

the most important information contained in a data set. PCA finds combinations of variables

that describe major trends in the data set. Mathematically, PCA is based on an eigenvector

decomposition of the covariance matrix of the variables in a data set. Given a data matrix X

with m rows of samples and n columns of variables, the covariance matrix of X is defined as

(equation 4.1) [1, 2]:

cov( )1

T X X

X m

=

− (4.1)

The result of the PCA procedure is a decomposition of the data matrix X into principal

components called score and loading vectors (equation 4.2) [1, 2]:

1 1 2 2 ...T T T T

n m i i k k n m X t p t p t p t p E

× ×= + + + + + (4.2)

Here, t i is the score vector, pi is the loading vector and E is the residual matrix. The score and

loading vectors contain information on how the samples and variables, respectively, relate to

each other. The direction of the first principal component (t 1, p1) is the line in the variable

space that best describes the variation in the data matrix X. The direction of the second

principal component is given by the straight line that best describes the variation not

described by the first principal component and so on. Thus, the original data set can be

adequately described using a few orthogonal principal components instead of the original

variables, with no significant loss of information. Plotting the first and second principal

component against each other, the score plot is obtained (figure 4.1) [1, 2].

Loading plot or “mapping of variables” can be viewed as the bridge between the variable

space and the principal component space. Like score vectors, loading vectors can be plotted

against each other. The loadings show how well a variable is taken into account by the model



52

components. The loadings can be used to understand how much each variable contributes to

the meaningful variation in the data, and to interpret variable relationships. They are also

useful to interpret the meaning of each model component [2].

Figure 4.1: The figure shows how the principal component axis are defined in order to construct the score plot

[2].

4.2 Outlier detection

Some samples can have values that are extremes compared to the other samples in the matrix.

They may not be representative for the system at all, or they may be due to errors inmeasurements. Such samples will often be found in the outskirts of the main “swarm” in the

score plot and are referred to as outliers (Figure 4.2). Outliers can be of the “mild” type as to

the left in the figure or the “extreme” type to the right. Other ways to detect samples that are

very different or have a high influence on the models is to look at the leverage. The leverage

is based on the idea that anything can be lifted out of balance if the lifter has a long enough

lever. This means that the principal component axes in the score plot can be influenced by a

sample that has a high leverage and thus give a bad model [1, 2].



53

Figure 4.2: The plot shows an example of how outliers are detected in the score plot [2].

A sample with high leverage that falls near the PC axis can reinforce the PC model. Special

attentions must therefore be paid to samples located far from the other samples in the score

plot or have a high leverage (i.e. higher influence). Such samples may contain valuable

information or the discrepancy is due to non-representative samples. To decide if a sample is

an outlier and should be deleted from the data set, or an extreme that is important in order to

get the true picture one have to carefully evaluate the specific samples and preferentially have

detailed knowledge of the system under investigation [1, 2].



54

References

1. Aske, N.K., H.; Sjoblom J., Energy & Fuels 2001. 15(5): p. 1304-1312.

2. Esbensen, K.H.G., D.; Westad, F.; Houmøller, L. P., Multivariate data analysis - inpractice: an introduction to multivariate data analysis and experimental design. 5 ed.

2001: Camo: Oslo. 598 s.



55

5. EXPERIMENTAL TECHNIQUES

Different analytical techniques have been utilized in this doctoral work. This chapter focuses

on the main experimental techniques that I have used, and will provide a theoretical

background for the different methods. Emphasis will be on practical aspects and interpretation

of results. The different techniques that have been used for the characterization of the

different crude oils (SARA - precipitation of asphaltenes and fractionation of maltenes by

HPLC, density, interfacial tension (IFT), interfacial elesticity and TAN) will not be treated in

this chapter. Instead the reader is adressed to the experimental section of each paper where

they have already been thoroughly described to get an insight.

5.1 Critical Electric Field (Ecritical)

Electro-coalescers are commonly used in the oil industry to enhance the separation of water

from crude oil. The electro-coalescer applies an electric field of 1-10 kV cm1− through the

flowing water-in-oil emulsion to enhance the flocculation and coalescence of the dispersed

water droplets. Basically, the water droplets increase their sizes through the electro-coalescer,

and thereby the water sedimentation rate is increased. There is a variety of factors influencing

the electrically-induced coalescence, such as the dielectric properties of the dispersed and the

continuous phase, the volume fraction of the dispersed phase, conductivity, size distribution

of the dispersed droplets, electrode geometry, electric field intensity, the nature of the electric

field (AC or DC), etc. An electric field cell containing a small volume of sample has been

developed for the determination of emulsion stability (figure 5.1). The method is similar to

the one employed by Aske et al. [1]. The cell for determining the critical field consist of aTeflon plate with a hole in the center (r = 5 mm), and a brass plate on each side. The distance

between the plates varies from 0.1 mm up to 1.0 mm, and the upper brass plate has holes for

sample injection. The brass plates are connected to a computer-controlled power supply

(Agilent Model 6634B) that can deliver a maximum of 100 V DC [1].



56

Figure 5.1: Illustration of the critical electric field cell used to measure emulsion stability of water-in-oil

emulsions [2].

The power supply can stepwise increase the voltage and measure the current passing through

the emulsion. A sudden increase of the current will indicate that the electric field has broken

the emulsion and that there will be a free transport of ions between the electrodes. The

corresponding electric field is the Ecritical value. Figure 5.2, illustrates how emulsions behave

under the influence of the applied field [2]:

Figure 5.2: Configuration of the emulsion droplets when increasing the applied electrical field [2].



57

A: When no field is applied, the water droplets are randomly distributed according to Stokes

law of sedimentation and Brownian motion. In addition, some degree of droplet flocculation

may be present.

B: As the field increases, the droplets line up between the electrodes due to polarisation of the

aqueous droplets containing electrolyte.

C: Finally, at some point, the applied electric field causes irreversible rupture of the interfacial

films between the droplets. The droplets coalesce, resulting in a water-continuous bridge

between the electrodes. The ions of the water phase contribute to a sudden increase in the

conductivity. The emulsion stability is hence defined as the strength of the field when the

conductivity suddenly rises.

5.2 Rheometry

Rheometry refers to the measuring techniques used to determine the rheological properties of

materials, where rheology is the flow of fluids and deformation of solids under various kinds

of stress and strain. Rheometry is an extremely useful tool for determining the flow properties

of various materials by measuring the relationships between stress, strain, temperature, andtime. Most rheometer models belong to three specific categories. These are the rotational

rheometer, the capillary rheometer, and the extensional rheometer. The most commonly used

of these is the rotational rheometer, which is also called a stress/strain rheometer.

In rotational methods the test fluid is continuously sheared between two surfaces, one or both

of which are rotating. These devices have the advantage of being able to shear the sample for

an unlimited period of time, permitting transient behavior to be monitored or an equilibrium

state to be achieved, under controlled rheometric conditions. Rotational methods can also

incorporate oscillatory and normal stress tests for characterizing the viscoelastic properties of

samples. Rotational measurements fall into one of two categories: stress-controlled or rate-

controlled. In stress-controlled measurements, a constant torque is applied to the measuring

tool in order to generate rotation, and the resulting rotation speed is then determined. If well-

defined tool geometry is used, the rotation speed can be converted into a corresponding shear

rate. In rate-controlled measurements, a constant rotation speed is maintained and the

resulting torque generated by the sample is determined using a suitable stress-sensing device,



58

such as a torsion spring or strain gauge. Some commercial instruments have the capability of

operating in either stress-controlled or rate-controlled modes.

A range of different measuring geometries is avaiable as accessory of rheomters, which canextend the measurement range. Most rheometers depend on the relative rotation about a

common axis of one of three tool geometries: concentric cylinder, cone and plate, or parallel

plates (figure 5.3).

Figure 5.3: Schematic diagram of basic tool geometries for the rotational rheometer: (a) concentric cylinder, (b)

cone and plate, (c) parallel plate [3].

The rheometric measurementscarried out in this thesis were performed using a Anton Paar

Physica MCR 301 and MCR 100 rheometers using a concentric cylinder geomerty [3-5].

The evaluation of shear stress with the shear rate for materials can be described by several

behaviours (figure 5.4):

• Newtonian fluids: The apparent viscosity is independent of the shear rate.

• Shear thinning (pseudoplastic) fluids: These fluids present a decrease of the apparent

viscosity when the shear rate increases.

• Shear-thickening (dilatant) fluids: Contrary to the former cases, the apparent viscosity

of these fluids increases with the shear rate.

• Bingham plastic fluids: An important characteristic of these materials is the presence

of a yield stress. Below this yield stress, a material exhibits solid like characteristics,

and we must apply a yield stress above this value to make the material flow [3].



59

Figure 5.4: Newtonian and non-Newtonian phenomena [6].

5.3 Nuclear Magnetic Resonance (NMR)

5.3.1 Introduction to the principle of NMR

Nuclei with an odd number of protons and neutrons possess a property called spin. In

quantum mechanics spin is represented by a magnetic spin quantum number. Spin can be

visualised as a rotating motion of the nucleus about its own axis. As atomic nuclei are

charged, the spinning motion causes a magnetic moment in the direction of the spin axis.

The magnetic moments or spins are constrained to adopt one of two orientations with respect

to B0, denoted parallel and anti-parallel. The angles subtended by these orientations and the

direction of B0 are labelled theta in figure 5.5 a). The spin axes are not exactly aligned with

B0, they precess around B0 with a characteristic frequency as shown in figure 5.5 b). This isanalogous to the motion of a spinning top precessing in the earth's gravitational field. Atomic

nuclei with the same magnetic spin quantum number as 1H will exhibit the same effects spins

adopt one of two orientations in an externally applied magnetic field.

The Larmor equation expresses the relationship between the strength of a magnetic field, B0,

and the precessional frequency, F, of an individual spin (equation 5.1):

0 B F γ = (5.1)



60

The proportionality constant to the left of B0 is known as the gyromagnetic ratio of the

nucleus. The precessional frequency, F, is also known as the Larmor frequency [7].

Figure 5.5: a) In the presence of an externally applied magnetic field, B0, nuclei are constrained to adopt one of

two orientations with respect to B0. As the nuclei possess spin, these orientations are not exactly at 0 and 180

degrees to B0. b) A magnetic moment precessing around B0. Its path describes the surface of a cone [7].

At any given instant, the magnetic moments of a collection of 1H nuclei can be represented as

vectors, as shown in figure 5.6. Every vector can be described by its components

perpendicular to and parallel to B0. For a large enough number of spins distributed on the

surface of the cone, individual components perpendicular to B0 cancel, leaving only

components in the direction parallel to B0. As most spins adopt the parallel rather than the

antiparallel state, the net magnetisation M is in the direction of the B0 field [7].

Figure 5.6: A collection of spins at any given instant in an external magnetic field, B0. A small net

magnetisation, M, is detectable in the direction of B0 [7].



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