Overview on petroleum emulsions, formation, influence and demulsification treatment techniques

1.1 Water production sources

Reservoirs naturally have water in the shape of a denser layer under the hydrocarbon sheet and usually this water is called formation water or produced water. Sometimes produced water comes from another source exactly from the surface as injected water for hydrocarbon compounds extraction to achieve high oil recovery.

Petroleum resources normally contain natural water or formation water mixed with petroleum in oil reservoirs. Fig. 1, gives a general imaginary of reservoir layers, where generally water sits below the hydrocarbon seams and formation water is slightly acidic. In addition, during the hydrocarbon compounds extraction, a drop in reservoir pressure. Consequently, water is used to maintain the reservoir pressure by injecting water into the water layers to enhance oil recovery. Moreover, to inject water, there can be water penetration from outside the reservoir zone, and thus, to ensure a continuous oil and gas production, the time when formation water reaches production well begins and production of water besides the hydrocarbons can be considered. This type of water is recognized as produced water or oilfield brine. Volume of by-product that is produced during oil and gas recovery operations is a mixture of several compounds, including injected water, formation water, treating chemicals and hydrocarbons, that are generally organized as oilfield produced water, natural gas produced water and coal bed methane (CBM) produced water, depending on the source (Chan et al., 2002; Reynolds and Kiker, 2003; Strømgren et al., 1995).

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Fig. 1

Reservoir layers (Igunnu and Chen, 2012).

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1.2 Volume of generated water

During crude oil and gas extraction, produced water is mostly created through the process. In general, oil and gas production from subsurface resources is accompanied by water or brine, which is also indicated as produced water. At the end of the reservoirs age, especially after using secondary or tertiary recovery methods, the amount of produced water from wells increases and usually exceeds the volume of the hydrocarbons before when compared with the first production stage. The percentage of water produced from reservoirs basically depends on two factors; location and reservoir age. Generally, the average for produced water can vary from a few percent in the first production stage to more than 95% in the end of exploitation. Universal experts approximate that for every barrel of crude oil, three barrels of produced water are created, which means that more than half of the reservoir production is water (Fakhru’l-Razi et al., 2009). There are two major ways for produced water removal. The first is by draining water to the sea. Water that is to be discharged into the sea is treated to achieve a certain quality level that is specified by local environmental policy. Depending on the spot, the range of 30 to 40 ppm is the highest average oil in water (OIW) content for drainage (Igunnu and Chen, 2012). The second way for produced water discharge is by reinjecting and pumping the water into a disposal or a production reservoir. Moreover, the reinjection way is more preferred than the first way in handling produced water from the subsea production and processing facilities. At the same time, the process also conducts several hazards, for instance reservoir souring or harmful formation due to decline in injectivity. Additionally, emulsified oil droplets and suspended solid particles in the produced water can fill holes in the reservoir and reduce the permeability of formation. This leads to one fact that high quality is strictly required for reinjection and discharge options in handling produced water (Paige and Sweeney, 1993). So the treatment methods of produced water can be divided into three types to ensure processing quality.

1.3 Overall onshore and offshore produced water

Total extraction of produced water is approximately 250 million barrels per day, while 80 million barrels per day is for oil and this reverses the contrast between water and oil production. Consequently, water to oil percentage is about 3:1 and this shows that water production is 70%. The global water extraction has grown since a decade ago and is still rising. Produced water production is usually matured in the old wells, but for driven down depends on the methods used for managing and entering of new oil wells into the service (Dal Ferro and Smith, 2007; Khatib and Verbeek, 2003). Fig. 2 gives an estimate of onshore and offshore produced water extraction since 1990 until 2014.

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Fig. 2

Overall water production of onshore and offshore (Dal Ferro and Smith, 2007).

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1.4 Elements influencing on volume of extraction water

Reynolds and Kiker (2003) estimated that there are several elements that affect the production volume of produced water besides the age of wells:

• Drilling well technique: basically there are two types of well, namely horizontal and vertical well, The horizontal well produced water production is more than that of vertical well, at the same level of drawdown or become the same production if the horizontal well drawdown is reduced.

• Location of well within homogeneous or heterogeneous reservoirs: the area of wells, especially homogenous reservoirs, take a part in decreasing the production of water, and at the same time the increase in production of horizontal reservoirs versus unstimulated vertical wells is related to the nature of area that is in contact with the wells.

• Diverse sorts of completion: generally there are two factors in these elements that ascertain rules. The first factor is to avoid drilling towards water area and second is an open hole method which permits testing of drilling regions. However, the second factor (perforated completion method) gives more control because the area can be perforated and tested.

• Water separation methods: there are several technologies that are used for treating and lifting water to reduce cost for wells that produce high amount of saline water.

• These technologies include treatment by using gelled polymers to shut-off water, dropping beam pump lifting costs and the power options help to drop the electrical costs and separation technologies.

• Water flooding and injection to enhance oil recovery: the production rate of oil wells will progressively drop with time, so use water flooding to maintain a steady production rate. As a result of water flooding, the water production ratio will become higher at the same time as the water injection volume increases. In this case, it is essential to treat water with chemical characteristics. This is very important for produced water treatment, or makeup to enable sealing, clay swelling and brine incompatibilities.

• Low mechanical integrity: mechanical problems cause a lot of water entries and one of these problems is casting holes which are caused by wear or corrosion, and splits caused by flows; extreme pressure can let undesirable fluids to enter and raise water production.

• Underground communications: usually difficulties in underground communications occur near reservoirs or wellbores. All these difficulties work on rising produced water. Near wellbore problems are fence failures, completions and route behind casing. Reservoir related challenges are channeling, coning, cresting across higher permeability areas or fractures and fracturing out of area.

1.5 Gas generated water toxic

During gas extraction, produced water is separated at the same time. However, the construction water and condensed water that are included in gas process is produced water. The characteristics of produced water that is extracted during gas production are distinguished by the molecular-weight contents, like ethylbenzene, toluene, xylene (BTEX) and benzene. All these contents are considered as light aromatic hydrocarbons compounds as compared to produced water that is produced from oil. In addition, these compounds make water relatively more toxic. At the same time, many research point out that produced water from oil platforms is about 10 times less toxic than water extracted from gas/condensate platforms (Jacobs et al., 1992). In addition, the water production volume from offshore gas fields is lower. Normally, chemical additives that are used during gas extraction consist hydrogen sulfide, dehydration and elimination compounds. In addition, there is a wide range of chemical elements that exist during water production from gas platforms. Chemicals include brines solution, additives and inorganic acids (Stephenson, 1992). The characteristics of produced water from offshore oil platforms are greatly different from produced water from gas platforms Jacobs et al. (1992) researched in the North Sea and found that pH and chlorides concentrations were 8.1 and 19 g/L, alternately. The pH for produced water from crude oil wells in the North Sea was 6 to 7.7, while 3.5 to 5.5 was from gas wells, which was more acidic. Chloride concentration was about 1 to 189 g/L for produced water from gas production, while produced water from oil wells was 12 to 100 g/L.

1.6 Coal bed methane water generated

Water production from coal bed methane (CBM) varies in three basic point compositions; influence on environments, production technique from oil and gas and traditional technique of produced water. Water content in the coal layers leads to a rise in hydrostatic pressure and this helps to adsorb methane on the crystal surface. One of the methods that is used to remove methane from the crystalline body is by decreasing the reservoir head in the coal layers. During extraction, water holds methane in the coal layers, while produced water is created at the same time. In addition, water quantity is the other point of difference in CBM produced water from oil and gas. produce water in production stage. The quantity of CBM produced aqueous phase is high in quantity at the first stage of production and reduces towards the final stage of production. Simultaneously, when the size of aqueous phase is decreasing in CBM, the quantity of methane extraction increases. There are two general ways to deal with produced water from CBM; one is by processing and pulling to the surface or reinjecting. The nature of produced water from CBM vary, depending on three point of the original depositional environment, i.e., nature of coal, and coal layers depth, and these properties alter across extraction regions (Jackson and Myers, 2002).

The amount of produced water increases with rise in CBM production, and at the same time, the concern about produced water influence on the environment is growing, while there are some suspicions related to the environment effect of these water. Moreover, relevant managers and engineer are keen on environmental safety. The data of produced water are increasing and there are several states which provide information about produced water. These sources include institutes and different states ground water information centers in the USA. The organizations which collect information, confirm the information, assessing the dependability and reliability of information is done through DOE and the Bureau of Mines, and the USGS organization. Simultaneously, not all data about the effect of CBM production are totally understood.

2.1 Poisonous impact on marine environment

Effects are identified as exposure of life to different chemical concentrations. Components that have influence are quantity of delivered water compounds and solution density. Thus, their potential effect on sea-going living beings are incorporated in the following points (Georgie et al., 2001):

• Decrease the release in environment.

• Sudden and longstanding sedimentation.

• Evaporation of light hydrocarbons compounds.

• The interaction between some species in seawater and physical-chemical of produced water have influence on delivered water segments.

• Adsorption on particulate material.

• Biodegradation of natural mixes to less complex mixes.

Inside the marine condition, it is important to recognize shallow, ineffectively flushed waterfront zones and the vast sea. For seaside processes, the accepting conditions can incorporate shallow, near shore zones, bogs and regions. There are many examinations done on destiny and impacts of water that is releaseed into the waterfront situations of the Gulf of Mexico (Rabalais et al., 1992). Rabalais et al. (1992), approved that released water has pollute impact and hat depend on size and concentration of regional hydrocarbon. Perceiving the potential for shallow-water impacts, EPA prohibited the releases of produced water into beach front waters with an eliminate period beginning in 1997 (Rabalais et al., 1992), noted that profound water and quick streams; thus, give more than satisfactory weakening. Moreover, in spite of the fact that residue contamination is obvious at most studied areas, impacts on the benthic groups might be restricted or not apparent. For offshore activities, key components cover concentration of constituents and different features of the constituents, for example, poisoning, bioavailability and shape. Real destiny and impacts fluctuate with volume and structure of the release and the hydrologic and physical qualities of the receiving environment (Rabalais et al., 1992). A key concern is the potential for poisonous consequences for living amphibian due to release water into the water environments, like estuarine and marine.

2.2 Examination of chronic toxicity

Most oil and gas offshore wells are subjected to chronic toxicity examination under EPA organization. The examination result was positive and showed that there was no poisonous water problems in the USA. In other countries, especially in North Sea, the researchers focused more on compound interactions effect of chemical martials and applied new methods to control produced water. For instance, in Norway, there are numerous programs applied to reduce poisonous discharges into the environment (Johnsen et al., 2000; Veil et al., 2004). Furthermore, these methods or programs depend on comparing the predicted from spirited concentrations of each element, without any concentration, and see the harmful effects on the environment. There are two basic assessment program models (DREAM) and dose-related risk applied to estimate the environmental impact factor (EIF). Moreover, this method depends on the quantitative work to estimate the impact of each extraction. This technique is very viable with Norwegian due to limited offshore production in the North Sea. At the same time this technique is not very common in the Gulf of Mexico because it is not workable in such area due to the large offshore extraction. The examination of chronic toxicity in the Gulf of Mexico provides poor control.

2.3 Additional influence concerns

The water production from wells increases with age of wells, and at the same time the production and treating prior to water from deep offshore platforms will rise. Furthermore, there is limitation in using common treatment methods of produced water due to the lake in the space and movement on the rigs. This lead to increase in challenges on which techniques should be applied for treating the produced water and understanding of compounds in the water, besides how these elements effect on the environment and which of these compounds will increase. In addition, the acute toxicity of produced water depends on concentration of compounds water and the inside production area. Chemical additives, antagonistic effects and synergistic can cause or increase the produced water acute toxicity (Veil et al., 2004).

3.1 Emulsion formation and stability

One of the most major problems in the petroleum industry, especially mature oil fields, is high water quantity accompanying crude oil extraction. Besides that, during desalting and steam treatment of crude oil, water is injected into the process. Generally, there are three important factors that cause emulsion in the petroleum industry, which are turbulent flows, pressure change in chokes valve and other valves during crude oil extraction. Emulsions play certain rules in increasing the cost of transportation and pumping of crude oil, facilitated corrosion and crude oil production equipment processing plant catalysts damage (Schramm, 1992a; Sjöblom et al., 1992, 1995). Schubert and Armbruster (1989), concluded there are three basics reason to form emulsion, which are:

• Interaction between two immiscible fluids, for example, oil and water.

• Existence of emulsifying agents inside the crude oil such as asphaltenes and resins.

• Diffusion of one liquid into another due to turbulence flow or mixing energy.

3.1.1

3.1.1 The impact of turbulence on emulsification

Disturbance or mixing energy was the first reason to create emulsion. That was what researchers concluded in the 1970s (Haegh and Ellingsen, 1977; Wang and Huang, 1979). Schubert and Armbruster (1989), found that turbulence in the pipeline flow helped to create emulsion by mixing two fluid-like flow system of crude oil and water. Besides that, turbulence has an impact on coalescence and break up of emulsions (Schubert and Armbruster, 1989). Turbulence suppression happens due to contact between emulsion droplets and other liquids (constant phase). The scientific reason behind the occurrence of turbulence suppression is that kinetic energy of one liquid (single-phased) becomes higher than the other two liquids (two-phased) at the same liquid flow rate. Furthermore, a portion of the kinetic energy is transferred to emulsions from the two-phased stream and this makes the kinetic energy of two-phased less than single-phased. At the same time, when the power or kinetic energy is transferred from single-phased to the particle, the turbulent strength is declined (Schubert and Armbruster, 1989). Fig. 4 clearly shows the stage of water-in-oil emulsions formation.

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Fig. 4

Water-in-oil emulsions formation (Hanapi et al., 2006).

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Kobayashi et al. (2002), did an experiment on emulsion formulation by using a membrane through injection of diffused phase into constant phase by the membrane pores. Besides, many researchers had reported about the impact of velocity flow of single-phased and several types of surfactant on membrane emulsification characteristics. These studies focused on three point effect of diameter range, surfactants on membrane emulsification and impact of several types of surfactant on emulsion stability.

3.1.2

3.1.2 The impact of asphaltenes, resins and other components on emulsification

Crude oil comprises of asphaltenes and resins (also called functional molecules). These molecules contain heteroatoms, such as nitrogen, oxygen and sulfur. This causes acidic and basic traits in petroleum-based fluids, and thus stabilize water-in-oil emulsions (Subramanian et al., 2017). Alphaltenes are regarded as having the strongest stability of water-in-oil emulsion, because they contain aromatic and polycyclic aromatic hydrocarbons, Fig. 5, shows the molecular structure for asphaltenes in Tulare crude oil.

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Fig. 5

Molecular structure for asphtenes in Tulare crude oil (Varadaraj and Brons, 2012).

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Before 40 years ago, researchers, concluded that asphaltenes take an important part in stabilizing of water-in-oil (W/O) emulsion. These days, the researchers have more understood the emulsification process than the past (Czarnecki, 2008; Sjöblom et al., 2003). Canevari (1982), showed or clear how asphaltene affect by preventing water droplets from coalescence by making a thick layer on the water surface droplets. In addition the asphaltene assistedemulsion stability by making high viscoelastic films surrounded the water droplets while resins reinforced the stability by replacing the asphaltene when the asphaltene connection decreased for a period of time. Generally, researchers have showed that the composition of crude oil is the most important factor in an emulsification process cover the type of asphaltene, resin and concentration of compounds. Aspaltenes cover a wide range of elements. Graham et al. (2008), classifying the elements into two types; binding and nonbinding, depending on the effect on emulsification process, where the elements that have impact on binding other nonbinding. Czarnecki (2008), found that after studying several fractions, each fraction has different compounds, such as sulfur and oxygen. In addition, after the emulsion is separated into two phases, there are some droplets which is unable to be separated by an interface. Varadaraj and Brons (2012), see there are many types of emulsion like W/O, W/O/W, O/W, etc. emulsions are inside the portion of rag. Furthermore they noted that the broken emulsion has high concentration of asphaltenes. There are many studies about emulsion and researchers have reached the fact that asphaltene has an impact on emulsification process (Gu et al., 2002; Kilpatrick and Spiecker, 2001; Yarranton et al., 2000). Synergistic compounds can be considered as other factors that help in stabilizing emulsion by forming rigid and elastic films around water droplets and one of the common synergistic compounds is resins. Mechanism of asphaltenes in working and matching intermolecular interactions are not totally understood. Research focus generally on emulsion stabilizing through asphaltenes and neglected to measure the exact stability (Kilpatrick and Spiecker, 2001). Besides, there are other factors, including inorganic and organic solid particles and waxes, can improve the stability of emulsions (Sztukowski and Yarranton, 2004). Asphaltenes construction is anonymous and asphaltenes can be known from the deposition of oil in aromatic hydrocarbons, like pentane and hexane. In addition, the molecular weight of asphaltene is approximately 750 Daltons and surrounded by other compounds, such as alkane, S, N, etc. (Groenzin and Mullins, 2007). Another factor, such as time, has side effects through enhanced the emulsion stability by rising the complex modulus by 2° in time; from 2 h to 4 h. This happens due to the impact of the time on crosslinking and aggregation of asphaltene on the interface film, and thus improves the film strength. The diffusion of asphaltenes on interface film in W/O emulsion showed the mechanism of emulsion formation. However, what caused emulsion stability is asphaltenes because asphaltenes are made into rigid, elastic and stable film (Lobato et al., 2007; Zhang et al., 2005). Arla et al. (2007), showed that some part of asphaltenes have more effects than the other part, especially the acid fraction in making W/O emulsion more stable. At the same time, many research (Spiecker and Kilpatrick, 2004; Yang et al., 2004), have approved that, the stability of emulsion basically depends on two-factor fractions and concentration of asphaltenes.

Other studies focused on the impact of resins on W/O emulsion (Fingas and Fieldhouse, 2009). Researcher have frequently noted on the impact of resins, in which one of them noted that if resins were added at a ratio of 2:1 (resins:asphaltenes) it will enhance the stability of W/O emulsion twice than without resins (Kilpatrick and Spiecker, 2001). Another study (Ali and Alqam, 2000), showed that, raising the ratio of (resins:asphaltenes) in crude oil will enhance the stability of W/O emulsion. Pereira et al. (2007), showed that resins can be found in crude oil, depending on the type of resins. The adsorption of resin on iterfical film depends on several factors, including silica and asphaltenes, however, some resins are more adsorptive on the same surface. Other studies showed that the important factor which can decide, whether resins would stabilize asphaltenes or not. is self-interaction. Silset et al. (2010), saw that several emulsion stabilities can be explained through the interaction between resins and asphaltenes atoms. In normal conditions, asphaltenes adsorb resins to enhance the aggregation and precipitation of asphaltenes. Other studies Spiecker et al. (2003), noted that resins work on solvated asphaltenes and besides that, they approve that there are interplays between the atoms of resins and asphaltenes. On the other hand, resins comprise surface active materials, which are aromatic ring, long-chain carboxylic acid, esters and phenols. Furthermore, resins could also develop an interfacial film structure of a particular strength. Since the stability of oil-in-water (O/W) emulsion in conjunction with resins is the strongest, and thus a higher absolute value of zeta potential for oil droplet surface. Nonetheless, wax comprises small occurrences of interfacial active materials, whereby it only comprises short-chain cycloalkanes and hydrocarbons, leading to the weakest stability of oil-in-water (O/W) and water-in-oil (W/O) emulsions developed by wax model oil oil (Zhang et al., 2016). There are less study on other factors, such as waxes have impact or not on W/O emulsion, at the same time, waxes have impact on some emulsions like food formulation when waxes are in molten or deformed shape (Binks and Rocher, 2009).

3.1.3

3.1.3 Emulsion thermodynamic aspect

The unchanged in emulsion properties for a certain period of time can be defined by term “emulsion stability”. In the same time, thermodynamically emulsion a considered as an unstable system and emulsion properties will change slowly as well as there are various phenomena that occur during the change in emulsion properties including creaming, flocculation, Ostwald ripening, coalescence, etc. However, these phenomena may occur combined together or individual. The emulsion is a system of two-phase or more than in most case have media with various densities. The difference density between droplets and continuous phase determine the movement of droplets. There are two phenomenon related two the movement of droplets creaming and sedimentation. Creaming phenomenon occurs when the droplets move up due to the low density of droplets reverse the sedimentation that happens when droplets move down due to high density. Generally, oil has a density less than the water, consequently, the sedimentation phenomenon takes place in water in oil emulsion and creaming phenomenon in oil in water emulsion (Derkach, 2009; Nollet, 2004; Robins, 2000; Robins et al., 2002). Single droplets velocity v in creaming emulsion which is not deformation can be found by Stokes formula (Nollet, 2004).

(1)

$$v=\frac{2g{r}^2({\rho }_{\mathit{cont}}-{\rho }_{\mathit{drop}})}{9{\eta }_{\mathit{cont}}}$$ where r, $g$ , ρ_cont, ρ_drop, η_cont are present droplet radius, gravity acceleration, continuous phase density, droplet density and continuous phase Newtonian viscosity. Other phenomenon is flocculation which is droplets are gathering in emulsion to form droplets flocs due to attractive interactions (Gupta et al., 2016). While the merging of droplets describe as coalescence phenomenon and the coalescence occur when the film between two droplets collapses (Marrucci, 1969). While the process of gradual growth of coalescence droplets into large droplet in emulsion is defined by Ostwald ripening terms as show in Fig. 6 which clear the thermodynamic aspect in nanoemulsions.

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Fig. 6

Thermodynamic phenomenon’s in nanoemulsions (Gupta et al., 2016).

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3.2 Classification of emulsion

There are many classifications for emulsion, the most common is by sorting emulsion into four types (Fingas and Fieldhouse, 2003; Fingas et al., 2003). Fingas et al. (2003), had classified emulsion into four basic types, depending on three factors; stability, appearance and rheological measurements, as shown below.

• Water-in-oil emulsion.

• Mesostable water-in-oil emulsions.

• Entrained water.

• Unstable water-in-oil emulsion.

Other research divided emulsion to three general groups, as follows (Kokal, 2005).

• Water-in-oil emulsion

• Oil-in-water emulsion

• Multiple emulsion

3.2.1

3.2.1 Water-in-oil emulsion

In the petroleum industry, water-in-oil emulsion is very common, as shown in Fig. 7. At the same time crude oil cannot be refined and transported, before the water-in-oil is broken into two-phased (Mukherjee and Kushnick, 1988; Xia et al., 2004). During the crude oil extraction, there are many contents accompanying crude oil, such as oily sludge, water and solid content. Concurrently, the percentages for these compounds are 30–50 wt% oil, 10–12 wt% solid content and 30–50 wt% water. The solid content works on enhanced emulsion by stabilizing through the adsorbed partials on interfacial film. The oily sludge in crude oil is harmful to human health, so it is important to apply crude oil for recovery in the sludge disposal (Elektorowicz et al., 2006; Hu et al., 2013; Zhang et al., 2012). Furthermore, the sludge recovery was reviewed many times (Hu et al., 2013). The stability of emulsion is affected by several factors including viscosity, water content, density and element content of crude oil, while the previous factors change, depending on the wells and change the emulsion stability (Rodionova et al., 2014; Roodbari et al., 2016). Asphaltenes, waxes, resins, etc. All can be considered as surface-active materials and these elements are absorbed at the interfacial film which prevent the water droplets from coalescence. At the same time, N-, O-, S-, SiAOH and SiAOA bonding works on improving the emulsion stability (McLean and Kilpatrick, 1997; Mukherjee and Kushnick, 1988; Oren and MacKay, 1977; Poindexter and Marsh, 2009; Thompson et al., 1985). Moreover, asphaltenes and resins are the most effective factors in enhancing the emulsion stability, while the asphaltenes are soluble in aromatic hydrocarbon, such as toluene but is not soluble in alkanes. In contrast, resins with asphaltenes is soluble in both aliphatic and aromatic solutions. The reason that made asphaltenes and resins to enhance the emulsion stability is due to hydrophilic functional groups in their structure (Yang et al., 2008). The interfacial films' rigidity depends on what is deposited on the surface, whether asphaltenic or resins, while asphaltenic will make the interfacial films stronger than resinous materials. Demulsification method can be used to break emulsion by weakening the interfacial film or immobile interfacial films, and this helps the droplets to coalescence. In addition, the elasticity and the emulsion stability are affected by several factors and the most important factors are aromatic degree, concentration of asphaltene and resin, resin-to-asphaltene percentage and dose of hydrophilic functional groups in crude oil (McLean and Kilpatrick, 1997; Mohammed et al., 1993; Xia et al., 2004). Resin can work in high concentration with asphaltene as a destabilizing agent due to the P-P and polar bonding (Graham et al., 2008; Schorling et al., 1999; Spiecker et al., 2003). The hydrocarbon phase is different from crude oil in water-in-oil emulsion and synthetic. Normally, nonionic surfactant can be used for emulsion stabilization (Chistyakov, 2001). There are noteworthy differences between the oilfield emulsions contents against demulsification and model emulsions, during the crude oil extraction, there are several inhibitors added like corrosion inhibitor, scale inhibitor, clay stabilizer, etc. (Zaid, 1987; Zolfaghari et al., 2016).

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Fig. 7

Optical microscopic image of W/O emulsion; (a) without surfactant and (b) with 200 ppm copolymer (Le Follotec et al., 2010).

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3.2.2

3.2.2 Oil-in-water emulsion

Due to various properties, from non-Newtonian behavior, elasticity and time emulsions have garnered attention as a very important topic of study for rheological investigations. The term “emulsions” is characterized by numerous blends of immiscible liquids, of which include polymeric substances. As a rule of thumb, one denotes mixtures of low molecular weight (e.g., water and oil). The various blends of emulsions can be widely observed in technological applications from pharmaceuticals, enhanced oil recovery and food processing, as well as biological systems. Fig. 8 shows oil-in-water emulsion, oil-in-water emulsion (i.e., oil submersed in highly-concentrated emulsions) could form when surfactants of the block copolymer type are used with volume fractions being higher than 0.96. This type of emulsion could be brought to balance by utilizing surfactants with a low HLB value. A single Maxwell element could appropriately represent the emulsion rheological behavior. While the shear varies in linear proportion to the volume fraction, a proper correlation between shear modulus as well as the ratio of interfacial tension to radius was not reported (Masalova et al., 2003). The difference with models currently available could be accredited to a strong interfacial tension, which is greater than those of equilibrium values. The stronger interfacial tension could explain the reason behind the lack of inversion occurrence within oil-in-water emulsion. The apparent viscosity (which scales as a minus fourth power of continuous phase volume fraction) within the continuous phase of emulsion relies greatly on volume fraction for the oil-in-water emulsion studies of current versus previous experiments (Pons et al., 1995).

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Fig. 8

Optical microscope images for O/W emulsion prepared with (A) Eucalyptus globulus and (B) Citrus limon (Sousa et al., 2014).

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Reducing the aeration of oil-in-water emulsion and density variance, decreases the velocity of oil droplet (single phase) in water phase (continues phase). Consequently, this makes O/W emulsion more stable eventually. Moreover, by reducing the density difference between two phases, this well help to prevent oil droplet as well as air-water surface and oil droplet from coalescence. During aeration, there are four parameters that can be manipulated to decrease the oil droplet in water velocity. This is done to optimize stabilization of powdered o/w emulsions. These parameters include the density difference between two phases, water phase viscosity, aeration speed and oil droplet diameter (Murakami et al., 2014). Droplet flocculation has a strong correlation with the creaming stability of monodisperse oil-in-water emulsions. Hydrodynamic effects and particle-particle interactions are responsible for the increase of droplet flocculation and reduction of droplet concentration. Consequently, this leads to the increase of creaming velocity, which could be modeled by utilizing equations formulated to model it in nonflocculated systems. However, for accurate modeling of this phenomenon, the increase of effective volume fraction due to flocculation should be noted as well. The results of the preceding phenomenon, studied by Chanamai and McClements (2000), bear many crucial implications towards the formulation of various commercially relevant emulsion-based products. The study was conducted to produce a stable O/W emulsion by using diesel as oil and sorbitan monooleate as the emulsifier. It was found that the optimal emulsifier dosage was 0.5% by volume and that lower emulsifier dosages led to unstable emulsions. The lack of emulsion stability at higher dosages was accredited to rapid coalescence and concentration. The next finding concluded that the increase of emulsion stability varied inversely with oil-to-water ratio. The optimal ratio was found to be 1:1 by volume. The third finding showed that higher stirring intensity resulted in emulsions, which were more stable; thus, the best stirring intensity was found to be 2500 rpm. Fourth, high temperature was shown to reduce emulsion stability, with the most optimal emulsifying temperature being 308 °C. Lastly, emulsion stability varied linearly with stirring time until 15 min. After this time, the stability varied inversely with stirring time because of the drop-out of emulsifier within the oil–water interface (Chen and Tao, 2005).

3.2.3

3.2.3 Multiple or complex emulsion

The term ‘multiple emulsions’ refers to soft materials made by outer droplets (i.e., droplets which are dispersed) which comprised of smaller droplets inside (i.e., inner droplets). Various applications may be satisfied by the multi-compartmental feature, comprising tight spaces in continuum, detailed prior by Binks and Rocher (2009). The common terminology for normal, double or multiple emulsions may be categorized as oil-in-water-in-oil (O/W/O) or water-in-oil-in-water (W/O/W). The various categorizations are based on the phase sequence of various scales. For this common terminology, the ‘water’ refers to any polar or aqueous phase and ‘oil’ refers to hydrophobic, or water-insoluble phase (Silva et al., 2016). In modern times, development of double or multiple emulsions comprises tiny water droplets interspersed amongst bigger oil globules, which are in turn interspersed among aqueous continuous phases (Bonnet et al., 2010). Even though multiple emulsion systems have been recognized in modern science, significant attention was paid to these systems only within the last 15 years. Photomicrograph representations of the water-in-oil-in-water multiple emulsion configuration drop are shown in Fig. 9. The two dispersed phases could clearly be perceived, whereby the small internal aqueous droplets which are surrounded by a surfactant-stabilizing layer, are interspersed amongst the oil phases. Consequently, this is interspersed in the outer equeous phase, which is also surrounded by surfactant layer (Florence and Whitehill, 1982). Water-in-oil-in-water emulsion poses the same advantages of water-in-oil emulsion while also having a lower viscosity because of the lower viscosity of the aqueous external phase. This characteristic makes the particular configuration more convenient to control and for applications like for injection (Florence and Whitehill, 1982).

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Fig. 9

Photomicrograph of typical w/o/w emulsion (Florence and Whitehill, 1982).

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Relatively small reproducibility is found within these unintended preparations which results in low level of multiple drops and instability. While multiple structures may appear in numerous liquid-liquid interactions, they are usually so unstable so as to be imperceivable (Florence and Whitehill, 1982).

3.2.4

3.2.4 Pickering emulsion

High sustained demands for energy with limited crude oil recovery leading to increase the demand for discovering new resources of energy and enhancement the techniques of crude oil recovery. The rare new resources of crude oil drive the oil producer to exploitation and enhancement the oil recovery as the only option to cover the world energy demands (Sharma et al., 2015). Pickering emulsion is suitable in applying for enhanced oil recovery (EOR) by stabilizing emulsion with nanoparticles (SiO₂ and clay) and oilfield polymer polyacrylamide (PAM) in the presence of surfactant (Sharma et al., 2014). Pickering emulsions can be described as the emulsion stabilized by solids molecules (Zolfaghari et al., 2016). Fig. 10 clear Pickering emulsions stabilize by carbonaceous materials. Pickering emulsion is characterized by environmentally friendly, biologically compatible and more stability against coalescence, thus Pickering emulsion application opens the door in petroleum, pharmaceuticals, biomedicine, cosmetics and food industries (Tang et al., 2015). Furthermore, Pickering emulsion formation including the diffusion the solid particles in the continuous phase, so the solid particles adsorb on water/oil interfacial file to make electrostatic and steric protective layer that prevent droplets coalescence. While the solid particles adsorption in two immiscible interphases depends on particles wettability (Tang et al., 2015). Pickering emulsions response to external triggers like light intensity, temperature, pH and other variables. Dai et al. (2018), investigate the effect of composite zein – propylene glycol alginate particles (ZPGAPs) on stabilizing oil in water Pickering emulsion. The result shows that (ZPGAPs) may help in stabilizing oil in water Pickering emulsion. In addition, the ionic strength has a significant effect on Pickering emulsion stability through changing the range and magnitude of electrostatic interactions (Dai et al., 2018). Xie et al. (2018), study the influence of particle concentration, homogenization speed, pH, oil type, size distribution on Pickering emulsion. The result shows that increasing homogenization speed and particle concentration increase the emulsion stability. While the pH and oil types show no effect on the stability of the emulsion. Schröder et al. (2018), use microfluidic cross-flow device to study the coalescence stability and formation Pickering emulsions by colloidal lipid particle (CLP). The result show particle coverage plays a major role in droplets coalescence. CLP has prevented droplets coalescence at high surface coverage and destabilizing emulsion at low surface coverage. In the petroleum industry, the application of stimuli-responsive Pickering emulsifiers may be enhanced the crude oil recovery, reduce the operation cost and reduce the demand for energy-intensive (Tang et al., 2015).

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Fig. 10

Optical micrographs at different storage times for (a) styrene/water Pickering emulsions and (b) water/styrene Pickering emulsions (Xie et al., 2018).

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4.1 Elastic and viscous modulus

Emulsion considers as a system consists from immiscible liquid two or more, while the stability of this system depends on the presence of adsorbed surfactant on the interfacial system (Lee et al., 1997). The calculations of rheology emulsion depend on interfacial tension because the shear forces on surfaces influence on deformation and internal circulation of droplets in the emulsion. Lee et al. (1997), suggest the following formula to find the macroscopic two-phase fluid stress tensor.

Crude oil with high percentage of asphaltenes is insoluble in n-heptane and naphthenic acids, besides that, this type of crude oil it is difficult to handle and refine. This is so because during crude oil production, produced water commonly emulsifies into the crude oil, and thus lead to water-in-oil emulsion (Varadaraj and Brons, 2012). There is an inverse relationship between the creaming rate and oil volume, while the creaming rate and oil volume correlated with viscosity. The creaming rate and oil volume can be calculated from steady state measurement and power law of fluid model. At the same time, the correlation between viscosity and creaming rate is linear and this can be observed in high emulsion concentrations. Low shear measurements (constant stress (creep) and oscillatory measurements) were described as among the most effective methods of predicting creaming or sedimentation of emulsions (Tadros, 2004). In addition, Table 2 shows the properties of interfacial film between oil and water droplets, the interfacial tension, interface elastic modulus (€) and emulsion stability at percentage ratio of 2:8 water-in-oil volume for 0.1 wt% of asphaltenes in crude oil (Varadaraj and Brons, 2012). High amount of water retained was found to correlate with high emulsion stability. The oil-water interfacial tension (γ) for 50:50 n-hexadecane/toluene solvent mixture was 33 mN/m. It was observed that types I, II, and III asphaltenes reduced γ to about 20 mN/m. This decrease in γ was not as much as the reduction of interfacial tension within conventional surfactants. Thus, n-interfacial activity of these asphaltenes or interfacial tension could not be considered as a reliable method of measuring interfacial activity of asphaltenes (Varadaraj and Brons, 2012).

There is no correlation between stability of emulsion and interfacial tension, as shown in Fig. 11, due to the direct surface action of asphaltenes and autonomy of interfacial tension with the type of asphaltene. Furthermore, this phenomenon shows that traditional models for emulsion stability (with oi-water interfacial tension (γ) as the primary stabilizing factor) could not entirely explain stability of asphaltene-stabilized water-in-oil emulsions (Varadaraj and Brons, 2012).

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Fig. 11

Interfacial tension versus emulsion stability (Varadaraj and Brons, 2012).

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The definition of emulsion stability is the resistance of dispersed phase droplet against coalescence. Asphaltenes, the mass percentage of aromatics components, resins, viscous modulus (G″) and elastic modulus (G′) are the main parameters that effect on emulsion stability (Wong et al., 2015). Next to asphaltenes and volatile aromatic compounds, storage or elastic modulus (G′) and loss or viscous modulus (G″) were shown to affect emulsions stability. It was previously reported that, when the viscous behavior of the fluid is less than the elastic behavior (G″oG′) of the fluid, the emulsions were comparatively stable, provided that both of the parameters were independent of the frequency in the linear viscoelasticity region. Linear viscoelasticity region (LVER) refers to the region where a system does not break down due to applied stress (Ortiz et al., 2010). In addition, natural surfactants of crude oil like asphaltenes affected by the elastic modulus. Maia Filho et al. (2012), reported the effect of adsorption of natural surfactant on the water-oil interface. The result present that these surfactants cause intermolecular interactions which lead to increasing the elastic behavior and work against oil-water emulsion interface. Derkach (2009), concluded that coalescence between droplet dispersed phase decrease when the increase inelastic behavior.

4.2 Time and speed mixing impact

Time plays a certain rule in destabilizing emulsion. Generally, after period of time, like one week or more, the water droplets become more reliable because unstable emulsion will be broken (Fingas and Fieldhouse, 2003, 2004). Some factors cannot be considered as affective factors in destabilizing the emulsion. like water content due to surplus water that can be found in crude oil. Emulsion stability can be improved by increasing the speed and mixing interval by reducing diameter size of oil water droplets in oil-in-water emulsion and increasing the stability and viscosity due to particle interaction between two phases (Ahmed et al., 1999). The colloidal surface and Brownian movement forces can be stronger than the hydrodynamic forces in the system where the diameter of dispersed droplets is less than 1 lm (Ahmed et al., 1999).

4.3 Size and diffusion droplets

In the petroleum industry, there are two common types of emulsion; water-in-oil and oil-in-water emulsion Generally, these two types have droplet of size 0.1 lm or larger and sometimes more than 100 mL. However, the emulsion viscosity is effected by droplet size and distribution of droplets. The distribution of small droplets in small area produces emulsion with high viscosity and stability (Zolfaghari et al., 2016). What makes emulsion more stable is that the small droplets need a longer time to coalesce, while an effective surfactant can enhance the coalescence of water droplets or oil droplets, depending on the type of demulsifier.

4.4 Temperature

Temperature rising has several impacts on destabilizing emulsion, including reduce the viscosityof continuous phase, increase the discrepancy between the dispread and continuous phase of emulsion and rising the quantity of droplets collisions through weakening of interfacial film between two phases (Mohammed et al., 1994). As a consequence, the increasing temperature at the same time disadvantage, including increased concentration percentage on interface due to reduction in oil viscosity (Mohammed et al., 1993). Temperature can affect surfactant solubility, whereby the temperature can have positive or negative impact on solubility, depending on the type of demulsifier. In addition, the solubility of nonionic surfactants in water decreases with rising temperature, in contrast with anionic surfactants (Bourrel et al., 1980). Correspondingly, the adsorption of nonionic surfactant at interfacial film reduces with rising temperature in oil-in-water emulsion, as a result to destabilizing emulsion (Hirasaki et al., 2010). In contrast, other published work showed that the increased temperature in extracting water from ASP flooding improved the emulsion stability (Nguyen et al., 2012), the reason behind this behavior was due to high salt content in the produced water which enhanced the adsorption of anionic surfactant at interfacial film.

4.5 Solids particles

The emulsion stability can be enhanced through soft solids particles, many factors including size, interactions and wettability of solids particles affect the effectiveness of solids particles. As a result to diffusing the particles on the surface of interfacial films of W/O emulsion will increase the rigid of interfacial film and improve the emulsion stability through preventing the coalescence of emulsion droplets. At the same time, fine solids particles can improve the stability of temperature impact through change in average and characteristics of interfacial films. Furthermore, the compressibility of interfacial films can be influenced by solids particles due to the impact of solid particles on solubility of demulsifier on interfacial films (Levine and Sanford, 1985; Tambe and Sharma, 1993).

4.6 Environment medium

The pH effectiveness on emulsion stability is related to oil phase, brine characteristics in emulsion and organic acids in crude oil can be influenced on demulsification process in water-in-oil emulsion. Normally, surfactants hydrophilicity normally rise with growth in pH value of emulsion. Acidic environment can help in producing water-in-oil emulsion in contract with basic and medium environments, which is more suitable to produce oil-in-water emulsion. At the same time, asphaltenic can be more rigid at low pH level and starts to become weaker with rising pH level. Alkaline environment has influence on asphaltenic and make mobile/unstable films, while the resinous, in contrast with asphaltenic, became stronger in alkaline environment and weaker at low or medium pH. In addition, ionization of surfactants at interfacial film of water or oil phase gave positive or negative charge for single phase droplets at low pH level, the ionization effect is caused through brine solution due to the interaction of salts atom and surfactant at interfacial film (Fortuny et al., 2007; Strassner, 1968). The best pH level that helps surfactant to separate with high efficiency of oil-in-water emulsion at medium or near to medium level (Azim et al., 2010; Zaki et al., 1996). The act of nonionics surfactant depends on the environment that works in and normally acts like anionics under basic environment or like cationic in acidic environment (Möbius et al., 2001). Acidic environment is the best condition to break emulsion and at the same time should avoid the corrosion in treatment equipment.

4.7 Spread phase salinity

The salinity in water normally works in reducing the hydrophilicity of surfactant through decrease in the interactions of water with surfactant at interfacial films (Goldszal and Bourrel, 2000; Martínez-Palou et al., 2013). It was noted that, increasing the salinity of water-in-oil emulsion by adding NaCl and decrease the interfacial film tension, at the same time the HLD can be adjusted from negative to zero through increased salinity system and enhance the surfactant efficiency (Bera et al., 2013; Gaonkar, 1992; Nguyen et al., 2012). In addition, the increase in salinity in water-in-oil emulsion increase the stability of the system due to the interaction between the native surfactants and aqueous phase (Fortuny et al., 2007). However (Goldszal and Bourrel, 2000), observed that when water-in-oil emulsion has various and high concentration of resins with high brine salinity would need more hydrophilic additives to separate the aqueous phase with high efficiency. Nonionic surfactant tolerance in salinity is more than in anionic surfactant, while the effect of salinity on stability of emulsion is contradictory (Ahmed et al., 1999; Moradi et al., 2010; X. Wang et al., 2010). At the same time, aqueous phase in water-in-oil emulsion with divalent cation is more stable than monovalent cation, while salinity water with divalent cation increases the demulsification efficiency in water-in-oil emulsion more than monovalent cation (Kuo and Lee, 2009; Perles et al., 2012; Salager, 2000). The optimal salinity can be defined or occurred when the interfacial film tension between surfactant and brine is the same between the surfactant and oil, while optimum point happened at lower separation time, surfactant dose, viscosity, IFT, high coalescence rate and maximum oil recovery (Sharma and Shah, 1985).

4.8 Water and oil content

There are many factors besides the other impact, such as asphaltene and resin. Basically, in demulsification, efficiency by using surfactant increases with increasing water content, while reducing the time and concentration of surfactant dose needs to increase the other the water in oil ratio in specific the percentage of water in range from 0.3 to 07 volumetric fraction (Borges et al., 2009). However, emulsion is broken faster with higher water content than lower content, at the same time emulsion viscous increases with increasing in water content (Mouraille et al., 1998; Thompson et al., 1985). In addition, increasing the volume of dispersed phase enhances the separation efficiency and average of coalescence due to rise in entropy for high collision between the single phase droplets (Menon et al., 1985; Zaki, 1997). It is observed that, reducing the volume of oil from 90% to 60% in oil-in-water emulsion lead to little separation of water droplets while less 50% will cause broken emulsion directly. Moreover, increasing the oil content in oil-in-water emulsion can change the type of emulsion from oil-in-water emulsion to water-in-oil emulsion, which is more stable due to high concentration of oil in continuous phase (Ahmed et al., 1999). Sometimes, the emulsion is formed for transportation purposes by reducing the viscous of mixture. What is important in this case is pour-point of emulsion to avoided freezing of mixture at low temperature (Zaki, 1997).

5.1 Measurement of stability

One of the most important tests that can be applied is the emulsion measurement stability. Measurement stability refers to the ease in broking emulsion to two-phase and there are several techniques to measure the emulsion stability (Kokal and Alvarez, 2003; Pal et al., 1992). Bottle test can be considered as one of the most common techniques to measure emulsion stability, while this method, including mixing surfactant with emulsion, dilution of emulsion and note the separation efficiency with increase in time. However, there are several techniques of bottle test, normally standard ASTM technique is used to measure the sediments and water in the system. Emulsion stability is connected with fast broken emulsion with time and surfactant concentration. For instance, at specific surfactant dose, the emulsion stability can be fined through the measurement the percentage of water separation at a certain period of time. In modern days, the new technique is proposed for determining the stability of emulsion quantitatively (Kokal and Wingrove, 2000). This new method is present to determine the complexity of emulsion. The index in bottle test is used to measure the complexity of emulsion, while the index start from zero to 100% total separation and this percentage is influenced by several factors, such as temperature, dose of surfactant and type of surfactant (Kokal and Wingrove, 2000).

5.2 Destabilizing emulsions and demulsification methods

The interfacial films that include water droplets are responsible for the emulsion stability. The emulsion that is broken into interfacial film should be destroyed so that the water droplets can coalesce. There are several factors that can help in weakening the interfacial film, as shown below.

• Decreasing agitation or shear force.

• Solids disposal.

• Rising temperature.

• Monitoring the emulsifying agents.

• Increasing time duration.

In the petroleum industry, there are different ways to separate or broken emulsion into two-phase oil and water. In addition, these methods depend on applying one of the methods below (Kokal and Alvarez, 2003; Pal et al., 1992).

• Applying chemical surfactant to emulsion.

• Raising the temperature of the system.

• Passing electrical fields to enhance the water droplets coalescence.

• Enhancing the physical characteristics of the mixture.

There are several ways to demulsification of emulsion (Arthur et al., 2005). A summary of demulsification techniques is as in Table 2.

5.3 Surface active agents (surfactants)

Surface active agents are essential materials and very common in different industries, including chemical, detergents, paints, etc. In addition, it is critical in the oil and gas industry, especially in oil recovery processes, at the same time it is also used in environmental protection. Consequently, it is necessary to understand the physical and chemical characteristics of surfactants, unaccepted characteristics and phase behavior is vital in the chemical industry. Furthermore, surface active agents mainly consist of two parts; one is hydrophilic and the other is hydrophobic. Fig. 12 shows the two parts of a surfactant atom. The understanding of surfactant phenomena, including the application of surfactant and the elements or compounds that form surfactant (Ottewill, 1984). In petroleum industries, the breaking emulsion through chemical demulsification by apply surfactant or demulsifiers as chemical additives is important methods. Table 3 represent different types of demulsifiers.

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Fig. 12

Basic schematic of a surfactant molecule (Shui et al., 2009).

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On other hands, hydrophilic-lipophilic balance (HLB) of demulsifier is an important factor that helps in determining the attraction of demulsifier into water or oil phase. The surfactants with high HLB number above 10 are hydrophilic and it has high attraction into the water phase. While surfactants have HLB lower 10 considered as lipophilic surfactant and attraction into the oil phase (Shehzad et al., 2018). HLB parameter is useful in selection demulsifier as well as the surfactant with HLB between 8 and 11.63 must have food performance in water in oil emulsion (Ojinnaka et al., 2016). According (Griffin, 1949), surfactant with HLB value between 7 and 9 considered as wetting agents, while the surfactant with HLB (4–6) can be applied as emulsifiers and surfactant with HLB (13–15) can be applied as detergents. Fan et al. (2009), investigate the effect of HLB number in destabilizing water in oil emulsion with the ratio (1:1) by using polyoxyethylene nonylphenols as a nonionic surfactant. The result shows that the surfactant with HLB 14.2 has high performance in braking emulsion reverse surfactant with high HLB that has less efficiency which may be due to the interaction between crude oil components and surfactant and long oxyethyl head groups. Charchari and Abdelli (2014), investigate the influence HLB value of non-ionic surfactants in aqueous solutions on extraction oil. The result clear that increasing the HLB of surfactant improve the enhanced oil yield. Yeşilyurt et al. (2017), study the effect of HLB number on water recovery, dewatering efficiency and flotation performance of hard bituminous coal slimes. It was concluded that the surfactant has HLB number equal to ten have the highest performance infiltration. Xu et al. (2018), study the effect (HLB), surface tension, infrared spectra and wetting time of anionic surfactants on coal dust wetting ability. It was concluded that reduce the wetting time have no influence on surface tension, while reducing surface tension leading to decreasing wetting time at low surfactant dosage. In addition, electrostatic repulsions and hydrophobic play a major role in the adsorption density as well as the surfactant with a high value of HLB has high ability to bring the coal dust into the bulk solution. Hassas et al. (2014), designed a special set-up to investigate the effect of surfactants HLB value on dewatering lignite particles. The result clear that the surfactant with HLB near to 10 has high performance in dewatering the ultrafine lignite, while the surfactants with lower HLB are suitable for dewatering reagents like hard coals. Jafarirad (2017), found that hydrophobic blocks of amphiphilic agents have a significant effect on surfactant micellar characteristics as well as the chain lengths of hydrophobic and hydrophilic have an influence on the micellar behavior of surfactant. Thus, it helps to design surfactant diversity on hydrophilic/lipophilic balance. Zhang and Wu (2018), clear the influence of hydrophilic surfactants including Tween 80, IGEPAL CO890, IGEPAL CO520 and sodium oleate with hydrophilic-lipophilic balance (HLB) range between 10 and 18 on bio-oil separation. The result present that the surfactants hydrophobic groups have a significant effect on oil separation. Tang et al. (2018), investigate the hydrophilic-lipophilic balance (HLB) based on non-ionic surfactants and the relationships between the levelness of the dyed samples and K/Sum value, (HLB) and reflectance. It was concluded that increasing HLB value increases the reflectance percentage and decreases the K/S_sum value as well as the optimum HLB value leading to high visual appearance a levelness of dyed samples. Jin et al. (2009), enhanced the direct dropping method to find the HLB value for Metarhizium anisopliae conidia during dehydration at various water content stages. The experimental result shows that the HLB value for Metarhizium anisopliae conidia was 8 and at the optimum value the dehydration percentage did not change, while the wetting time significantly increased. Finally, it was concluded that the hydrophilic-lipophilic balance (HLB) value of a surfactant is a crucial factor that helps in selecting surfactant for a specific application. Actually, The hydrophilic-lipophilic balance (HLB) is a skill that uses for seeing the tendency of surfactant between water and oil phase as well as HLB value help in development advanced emulsification method (Yamashita and Sakamoto, 2016).

5.4 General classification of surface active agents

There are several ways to classify surface active agents and the most common one depends on the nature of the hydrophilic part. Normally there are three basic types, cationic, anionic and amphoteric. Gore et al. (2000), updated a list of existing surfactants. van Os et al. (2012), reported the physicochemical characteristics of different types of surfactant, including nonionic and cationic. Porter (1994), published a useful book on surfactant. In addition, polymeric surfactant is one type of surfactant that use to formation emulsions and suspensions their elements, Fig. 13 shows the common types of surfactant.

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Fig. 13

Shows general types of surfactant.

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