Dispersions, emulsions, and foams

CHAPTER

Dispersions, emulsions, and foams

21

Actually, there is no common generic technical term that includes these different subtopics. The admittedly clumsy term small scale heterogenic materials created by the author would not be adequate as a title for this chapter. Some authors use the term dispersion as generic term that includes emulsions, c.f., Table 21.1. Note that there is a difference, depending on the size of he particle. If the particle site is in the range of the size of a molecule, the dispersion is addressed as a solution. Between the nanometer and micrometer size, the particle are colloid like, and above this range we are dealing with a suspension. In fact, emulsions, dispersions, and foams are related from the view of their physical laws of stability, preparation, and destruction. Monographs on the basic issues of these topics are available [2–5].

21.1 DISPERSIONS In the realm of oilfield applications dispersions consist mostly of finely distributed solids in a liquid, however, also other physical states are appropriate, c.f., Table 21.1. Dispersions have been reviewed in the literature [6–9] Subsequently, special dispersants in oilfield applications will be dealt with.

21.1.1 DISPERSANTS Dispersants are also addressed as dispersing agents. Dispersants are used to improve the separation of particles. Further, they are used to prevent settling or clumping. Dispersants are used in several disciplines beyond oil filed applications [10]. Dispersants are related to surfactants, as they contain usually surfactants. However, the term surfactant is more general. The use of surfactants includes detergents, wetting agents, emulsifiers, foaming agents, and last but not least dispersants. Sloppily spoken, let us state that dispersants are used to create slurries, whereas surfactants are used to create emulsions. However, the border is blurred. In the oilfield industry, the term surfactant is targeting mostly to emulsifying agents for fluids. In contrast, the major fields of the application for dispersants include cement slurries, oil spill treating agents, and transport applications. Subsequently dispersants for the most important applications are collected. Petroleum Engineer’s Guide to Oil Field Chemicals and Fluids. http://dx.doi.org/10.1016/B978-0-12-803734-8.00021-7 © 2015 Elsevier Inc. All rights reserved.

741

742

CHAPTER 21 Dispersions, emulsions, and foams

Table 21.1 Examples for Dispersions [1] Dispersed

Continuous

Colloid

Liquid Solid Gas Liquid Solid Gas Liquid Solid

Gas Gas Liquid Liquid Liquid Solid Solid Solid

Fog Smoke Foam Microemulsion Pigmented ink Styrofoam Gel Solid sol

Suspension Dust Foam Emulsion Soil Sponge Granite

Aqueous drilling muds Low molecular weight dispersants Complexes of tetravalent zirconium and ligands selected from organic acids such as citric, tartaric, malic, and lactic acid and a complex of aluminum and citric acid are suitable as dispersants [11–14]. This type of dispersant is especially useful in dispersing bentonite suspensions. The muds can be used at pH values ranging from slightly acidic to strongly basic.

Synthetic polymers Polymers containing maleic anhydride. A mixture of sulfonated styrene-maleic anhydride (MA) copolymer and polymers prepared from acrylic acid (AA) or acrylamide (AAm) and their derivatives [15] are dispersants for drilling fluids. The rheologic characteristics of aqueous well drilling fluids are enhanced by incorporating into the fluids small amounts of sulfonated styrene-itaconic acid copolymers [16] and an AA or AAm polymer [17]. Sulfonated styrene-maleimide copolymers are similarly active [18]. Examples of maleimide monomers are maleimide, N-phenyl maleimide, N-ethyl maleimide, N(2-chloropropyl) maleimide, and N-cyclohexyl maleimide, c.f. Figure 21.1. N-aryl and substituted aryl maleimide monomers are preferred. The polymers are obtained by free radical polymerization in solution, in bulk, or by suspension. In copolymers containing the styrene sulfonate moiety and MA units, the MA units can be functionalized with an alkyl amine [19–24]. The water-soluble polymers impart enhanced deflocculation characteristics to the mud. Typically, the deflocculants are relatively low molecular weight polymers composed of styrene sodium sulfonate monomer, MA, as the anhydride or the diacid, and a zwitterionic functionalized MA. Typically the molar ratio of styrene sulfonate units to total MA units ranges from 3:1 to 1:1. The level of alkyl amine functionalization of the MA units is 75-100 mol%. The molar concentrations of sulfonate and zwitterionic units are not necessarily equivalent, because the deflocculation properties of these water-soluble polymers can be controlled via changes in their ratio.

21.1 Dispersions

O

O

N CH2

CH CH3

N CH2

CH3

Cl O

O

N-(2-Chloropropyl) maleimide O N O N-Cyclohexyl maleimide

N-Ethyl maleimide O N O N-Phenyl maleimide

FIGURE 21.1 Imides.

Alternating 1:1 copolymers of sodium methallylsulfonate and MA are useful as water-soluble dispersants [25]. The copolymers are produced by free radical polymerization in acetic acid solution. Because of their high solubility in water and the high proportion of sulfonate salt functional groups, these alternating polymers are useful as dispersing agents in water-based drilling fluids.

Acrylics. Low-molecular weight copolymers of AA and salts of vinyl sulfonic acid have been described as dispersants and high-temperature deflocculants for the stabilization of the rheologic properties of aqueous, clay-based drilling fluids subjected to high levels of calcium ion contamination [26, 27]. Divalent ions, such as calcium ions or magnesium ions, can cause uncontrolled thickening of the mud and large increases in filtration times of fluids from the mud into permeable formations. A flocculation of the mud can occur in high-temperature applications. This flocculation increases the thickening effects of certain chemical contaminants and deactivates or destroys many mud thinners, which are used to stabilize the muds with respect to these effects. Poly(acrylic acid), or a water-soluble salt, having a molecular weight of 1.5-5 kDa, measured on the respective sodium salt and a polydispersity of 1.05-1.45, has been described as a dispersant for a drilling or packer fluid [28]. Copolymers or terpolymers of AA, which contain from 5 to 50 mol% of sulfoethyl acrylamide, AAm and sulfoethyl acrylamide, ethyl acrylate and sulfoethyl acrylamide, AAm and sulfophenyl acrylamide, and AAm and sulfomethyl acrylamide, are claimed to be calcium tolerant deflocculants for drilling fluids [29]. In general, 0.1-2 lb of polymer per barrel of drilling fluid is sufficient to prevent the flocculation of the additives in the drilling fluid.

743

744

CHAPTER 21 Dispersions, emulsions, and foams

A salt of a polymer or copolymer of acrylic or methacrylic acid (MA), in which the acid is neutralized with alkanolamines, alkyl amines, or lithium salts [30], is suitable as a dispersing agent. Polymers with amine sulfide terminal moieties. Amine sulfide terminal moieties can be imparted into vinyl polymers by using aminethiols as chain transfer agents in aqueous radical polymerization [31]. The polymers are useful as mineral dispersants. Other uses are as water treatment additives for boiler waters, cooling towers, reverse osmosis applications, and geothermal processes in oil wells, as detergent additives acting as builders, antifilming agents, dispersants, sequestering agents, and encrustation inhibitors. Polycarboxylates. Polycarboxylated polyalkoxylates and their sulfate derivatives may be prepared by reacting an ethoxylated or propoxylated alcohol with a watersoluble, alkali or earth alkali metal salt of an unsaturated carboxylic acid [32]. The reaction occurs in aqueous solution in the presence of a free radical initiator and gives products in enhanced yield and reduced impurity levels, compared with the essentially anhydrous reactions with free carboxylic acids, which have been used otherwise. The method provides products that give solutions that are clear on neutralization, remain clear and homogeneous on dilution, and are useful as cleaning agents in drilling and other oilfield operations.

Natural modified polymers Modified poly(saccharide)s. Phosphated, oxidized starch with a molecular weight of 1.5-40 kDa, with a carboxyl degree of substitution of 0.30-0.96, is useful as a dispersant for drilling fluids [33]. Physical mixtures consist of reversibly crosslinked and uncrosslinked hydrocolloid compositions and hydrocolloids. These show improved dispersion properties [34]. Sulfonated asphalt. Sulfonated asphalt can be produced as follows [35]: 1. heating an asphaltic material, 2. mixing the asphalt with a solvent, such as hexane, 3. sulfonating the asphalt with a liquid sulfonating agent, such as liquid sulfur trioxide, 4. neutralizing the sulfonic acids with a basic neutralizing agent, such as sodium hydroxide, 5. separating solvent from the sulfonated asphalt, 6. recovering the evaporated solvent for reuse, and 7. drying the separated, sulfonated asphalt by passing it through a drum dryer. This is a batch-type process in which the rates of flow of the solvent, the asphaltic material, the sulfonating agent, and the neutralizing agent and the periods of time before withdrawal of the sulfonic acids and the sulfonated asphalt are coordinated according to a predetermined time cycle. The dried sulfonated asphalt can then be used in the preparation of drilling fluids, such as aqueous, oil-based, and emulsion types. Such drilling fluids have excellent

21.1 Dispersions

rheologic properties, such as viscosity and gel strength, and exhibit a low rate of filtration or fluid loss.

Humic acids. Coal with a mean particle size of less than 3 mm is slurried with water and then oxidized with oxygen or mixtures of oxygen and air at temperatures ranging from 100 ◦ C to 300 ◦ C, at partial oxygen pressures ranging from 0.1 to 10 M Pa and reaction periods ranging from 5 to 600 min [36]. In the absence of catalysts, such as alkaline bases, the main products of oxidation are humic acids. These humic acids are not dissolved because the pH of this slurry is in the range of 4-9. Small amounts of fulvic acids are formed, and these are soluble in the water of the slurry. The coal-derived humic acids find applications as drilling fluid dispersants and viscosity control agents, whereas the coal-derived fulvic acids may be used to produce plasticizers and petrochemicals.

Cement Dispersants are used in well cement slurries. For this application, the dispersant should be water-soluble. The dispersants prevent high initial cement slurry viscosities and friction losses when the slurries are pumped.

Poly(melamine sulfonate) and hydroxyethyl cellulose For oilfield cement slurries containing microsilica, sodium poly(melamine sulfonate) and hydroxyethyl cellulose may be used as dispersing agents [37–39]. Melamine is shown in Figure 21.2. The cement slurries may contain up to 30% of microsilica (i.e., colloidal silica), silica flour, diatomaceous earth, or fly ash with particle dimensions between 0.05 and 5 µ m. The slurries may further contain conventional additives, such as antifoaming agents and set retarding agents, etc.

Poly(ethyleneimine) phosphonate derivatives In oil and gas well cementing operations, poly(ethyleneimine) phosphonatederivative dispersants enhance the flow behavior of the cement slurry [40]. The slurry can be pumped in turbulent flow, thereby forming a bond between the well casing and the rock formation.

NH2 OH H2N 2-Naphthol

N

N N

O NH2

Melamine

FIGURE 21.2 2-Naphthol, melamine, and p-aminobenzoic acid.

H2N

C OH

p-Aminobenzoic acid

745

746

CHAPTER 21 Dispersions, emulsions, and foams

Acetone formaldehyde cyanide resins An aqueous solution of acetone and sodium cyanide is condensed by adding formaldehyde at 60 ◦ C. A resin with nitrile groups is obtained. A similar product with sodium sulfite can be obtained. These products are dispersants for cements [41, 42]. The dispersant properties of the composition can be enhanced by further reacting the composition with a hydroxide.

Napthalenosulfonic acid formaldehyde condensates A dispersing agent for a cement slurry is the magnesium salt from the condensation of napthalenosulfonic acid and formaldehyde [43, 44]. The additive eliminates free water, even at low temperatures and in particular with those cements most susceptible to this phenomenon.

Sulfoalkylated naphthols Sulfoalkylated naphthol compounds are effective as dispersants in aqueous cement slurries. The compounds can also be applied in an admixture with watersoluble inorganic compounds of chromium to provide additives of increased overall effectiveness. Particularly suitable are sodium chromate or ammonium dichromate. α-Naphthol is reacted in an alkaline aqueous medium with formaldehyde to create condensation products. The aldehyde can be reacted with bisulfite to produce sulfoalkylated products [45, 46].

Azolignosulfonate A cement dispersant has been described that is an azolignosulfonate formed from the coupling of a diazonium salt, made from sulfanilic acid or p-aminobenzoic acid, and a lignosulfonate [47]. The dispersant can reduce the aqueous cement slurry viscosity or thin the cement composition to make the cement slurry pumpable without significantly retarding the set time of the cement slurry. The azo structure is formed by coupling lignosulfonate with diazonium salt. It masks the retardation effect of the phenolic group in the lignosulfonate molecule.

Polymers from allyloxybenzene sulfonate Water-soluble polymers of allyloxybenzene sulfonate monomers can be used as dispersants in drilling fluids and in treating boiler waters in steamflooding and as plasticizers in cement slurries [48, 49]. The preferable molecular weight range is 1-500 kDa.

Sulfonated isobutylene maleic anhydride copolymer A dispersant that can be used in drilling fluids, spacer fluids, cement slurries, completion fluids, and mixtures of drilling fluids and cement slurries controls the rheologic properties of and enhances the filtrate control in these fluids. The dispersant consists of polymers derived from monomeric residues, including low molecular weight olefins that may be sulfonated or phosphonated, unsaturated dicarboxylic acids,

21.1 Dispersions

ethylenically unsaturated anhydrides, unsaturated aliphatic monocarboxylic acids, poly(vinyl alcohol)s (PVA)s and diols, and sulfonated or phosphonated styrene. The sulfonic acid, phosphonic acid, and carboxylic acid groups on the polymers may be present in neutralized form as alkali metal or ammonium salts [50, 51].

Miscellaneous dispersants A nonpolluting dispersing agent for drilling fluids [52–54] has been described. The agent is based on polymers or copolymers of unsaturated acids, such as AA or MA, with suitable counter ions.

Sulfur The deposition of elemental sulfur in conduits through which a sulfur containing gas is flowing can be reduced by providing a sulfur dispersant. The dispersant is an adduct of a primary alcohol and epichlorohydrin, mixed with an aliphatic amine component [55].

Asphalts Certain petroleum products, including, heavy crude oils and residual fuel oils, are rich in asphaltenes. The presence of asphaltenes can lead to various problems in the recovery and transportation of the products. This results in increased viscosity, formation of stable emulsions, fouling and corrosion [56]. Certain alkyl-substituted phenol-formaldehyde resins can act as dispersants for asphalts and asphaltenes in crude oils [57]. The dispersants help keep asphalt and asphaltenes in dispersion and inhibit fouling, precipitation, and buildup in the equipment. Further, asphaltenes in petroleum products can be stabilized with amine-chelate complexes. Improved compositions contain ethylene diamine tetraacetic acid, a fatty acid amide, and an imidazoline amide compound [56]. The compounds are shown in Figure 21.3.

Oil spill Dispersants for oil spill applications are sprayed onto oil slicks in order to remove oil from the sea surface and disperse it into the aqueous phase. In addition, dispersants reduce the environmental impact of the spilled oil as they are removing the spill from the surface of the water. Moreover, dispersants can be used under harsh weather conditions, in that mechanical collection may not otherwise be possible. The dispersion process accelerates the degradation of the oil by natural processes [58]. However, prior to the use of a certain dispersant, consideration must be given to the impact of the dispersed oil on sub-surface resources, such as fish stocks and coral. In addition, it is essential that the limitations of dispersants are recognized so that they will be used effectively. [59]

747

748

CHAPTER 21 Dispersions, emulsions, and foams

O C15H31

OH

N

OH Fatty acid amide O N N H (CH2)7

(CH2)7

(CH2)7 (CH2)7

CH3

CH3

N Imidazoline amide

FIGURE 21.3 Asphaltene dispersants [56].

Ethoxylated sorbitol oleate and mixtures are suitable for emulsifying or dispersing spilled petroleum products in either terrestrial or marine environments [60]. A fully integrated and effective response to an oil or chemical spill at sea must include a well planned and executed post-incident assessment of environmental contamination and damage. Case studies of the use of oil spill dispersants haves been reported [58, 61].

21.2 EMULSIONS Emulsions play an important role in fluids used for oilfield applications. These include most importantly drilling and treatment fluids. Actually in these fields of applications, the emulsions are not addressed as such, rather, e.g., as oilbased drilling muds (OBM)s or water-based drilling muds, which are essentially emulsions from the view of physics. Here we summarize some basic aspects of emulsions. Oilfield emulsions are sometimes classified based on their degree of kinetic stability [62, 63]: • • •

loose emulsions: those that will separate within a few minutes. The separated water is sometimes referred to as the free water. medium emulsions: They will separate in a some 10 min. tight emulsions: They will separate within of hours, days, or even weeks. Thereafter, the separation may not be complete.

Emulsions are also classified by the size of the droplets in the continuous phase. When the dispersed droplets are larger than 0.1 µ m, the emulsion is a macroemulsion [63].

21.2 Emulsions

From the purely thermodynamic view, an emulsion is an unstable system. This arises because there is a natural tendency for a liquid-liquid system to separate and reduce its interfacial area and thus its interfacial energy [62]. A second class of emulsions is known as microemulsion. Such emulsions are formed spontaneously when two immiscible phases are brought together with extremely low interfacial energy. Microemulsions have very small droplet sizes, less than 10 nm, and are stable from the view of thermodynamics. Microemulsions are fundamentally different from macroemulsions in their formation and stability.

21.2.1 INVERT EMULSIONS Invert emulsions have a continuous phase that is an oleaginous fluid, and a discontinuous phase that is a fluid, which is at least partially immiscible in the oleaginous fluid. Actually, invert emulsion are water-in-oil emulsions. Invert emulsions may have desirable suspension properties for particulates like drill cuttings. As such, they can easily be weighted if desired. It is well known to reverse invert emulsions to regular emulsions by changing the pH or by protonating the surfactant. In this way, the affinity of the surfactant for the continuous and discontinuous phases is changed [64]. For example, if a residual amount of an invert emulsion remains in a well bore, this portion may be reversed to a regular emulsion to clean out the emulsion from the well bore. Invert emulsion compositions can be used, where the organic phase is gelled. For example, diesel can be gelled with decanephosphonic acid monoethyl ester and a Fe3+ activator [64]. Polymers are often used to increase the viscosity an aqueous fluid. The polymer should interact with this fluid as it should show a tendency to hydrate. Microemulsions may be helpful to achieve this target [65].

Breakers As breakers for invert emulsions, polymerized linseed oil reacted with diethanolamine has been proposed [66]. Breakers are described in more detail in Chapter 17.4.10.

Drilling fluid systems Invert emulsion fluid systems tend to exhibit high performance with regard to shale inhibition, borehole stability, and lubricity. However, invert emulsion fluid systems have a high risk of loss of circulation [67]. Latex additives can counterbalance this drawback, but since water must be added, an oil base drilling fluid system becomes an unbalanced invert emulsion system with different rheological properties. It is possible to rebalance an unbalanced invert emulsion fluid system. Conventionally, an unbalanced invert emulsion fluid system would either have to be rebalanced in the field or transported offsite to be rebalanced.

749

750

CHAPTER 21 Dispersions, emulsions, and foams

There are special formulations that avoid this drawback. The latex particles are not dispersed in the oil base continuous phase. Rather, the latex particles are dispersed in the emulsified aqueous phase. In fact, one of the advantages of invert emulsion fluids is that they can achieve at least some of the benefits of having an aqueous phase without requiring the aqueous phase to be in direct contact with the borehole wall [67].

Drill cuttings removal It is often necessary to drill a wellbore through geological formations the constituent materials of which swell or disintegrate on contact with water. In such cases an OBM is used, that is a fluid in which the liquid phase consists of oil, or of water-in-oil emulsions which are known in the art as invert emulsion fluids [68]. Invert emulsion types of mud have many advantages however, these must be weighed against environmental problems, in particular for offshore drilling. The mud itself is always recycled but the cuttings have to be removed after separating them on the surface using mechanical separators for separating out the solids [69]. These are vibratory screens, hydrocyclones, and centrifuges. Under the strictest regulations, it is permitted to discharge cuttings into the sea only when the cuttings contain less than 1% of organic substances. This amount is greatly exceeded by using an invert emulsion type mud because the film of the mud which contaminates the cuttings cannot be eliminated using mechanical techniques. Therefore it has been proposed to wash the cuttings before discharging them to the sea. However, the surfactants added to stabilize the invert emulsion are so effective that the washing water itself is emulsified in the mud, so the oil is dispersed in the washing water. Furthermore, both the volume and the viscosity of the mud increase [69]. The addition of detergents to destabilize such emulsions is largely ineffective. Moreover, detergents themselves cause environmental problems [69]. The combination of a non-ionic alkoxylated surfactant and an anionic sulfonate surfactant yields a stable invert emulsion. This is surprising, because neither of these agents, when used alone, is capable of producing such an effect. The stable invert emulsion will rapidly and completely destabilize and disperse by simple admixture with low salinity waters [68]. According to such a principle, the cuttings are separated from the wellbore fluid and then washed with a wash water until the emulsion destabilizes. Alternatively, the separated cuttings are brought into contact with a water, which will destabilize the emulsion [68]. For copolymers with poly(oxyethylene) grafts the stability of a direct oil-in-water emulsion increases with the proportion of grafts and with their length. Hydrophobic modified poly(acrylates), with a hydrophilic backbone modified with long chain alkyl acrylates or alkyl methacrylates can be used as surfactants [70]. Such emulsions can be destabilized by adding an electrolyte. A statistical copolymer from 2-acrylamido-2-methyl-1-propane sulfonic acid acrylate can be modified by amidification with n-alkylamines, such as

21.2 Emulsions

di-n-dodecylamine [69]. Depending on the degree of modification of the monomers, the polymers are effective as stabilizers for direct or invert emulsions. The emulsion can be destabilized or reversed by reducing the salinity of the aqueous phase or neutralizing the acid. This phenomenon is used with advantage in fluids employed for petroleum or analogous wells, in particular drilling, fracturing, acidizing, or completion fluids [69]. Thinners may be added to invert emulsions. Anionic surfactants are used, particularly from the group of fatty alcohol sulfates. Thinners, which reduce the viscosity of drilling fluids at low temperatures are oxethylated fatty acids [71].

21.2.2 WATER-IN-WATER EMULSIONS When two or more different water-soluble polymers are dissolved together in an aqueous medium, it is sometimes observed that the system phase separates into distinct regions. Particularly, this happens when two polymers are chosen that are each water-soluble but thermodynamically incompatible with each other. These emulsions are termed as water-in-water emulsions, or also aqueous two-phase systems [72]. In the food industry, such fluids are used to create polymer solutions that mimic the properties of fat globules. In the biomedical industry, such systems are exploited as separation media for proteins, enzymes, and other macromolecules that preferentially partition to one polymer phase in the mixture. Aqueous two-phase polymer-polymer systems are also of interest in oilfield applications. These mixtures can be used to create low viscosity pre-hydrated concentrated mixtures to allow the rapid mixing of the polymers at a well site to achieve a low viscosity polymer fluid. Solutions of guar and hydroxypropyl cellulose (HPC) form aqueous phaseseparated solutions over a range of polymer concentrations. A phase-separated mixture can be formed by simultaneously dissolving dry guar and dry HPC in a blender. After continued stirring the solution is allowed to rest to achieve phase separation. Afterwards, the phase-separated solution can be gently stirred to remix the guar-rich and HPC-rich phases. The two-phase polymer solution can be activated to become an elastic gel by thermal treatment, or by changing the ionic strength [72]. This behavior can be used for zone isolation.

21.2.3 OIL-IN-WATER-IN-OIL EMULSIONS Oil-in-water-in-oil emulsions can be used as a drive fluid for enhanced oil recovery operations or as a lubrication fluid. Such emulsions exhibit improved shear stability and shear thinning characteristics in comparison to water-in-oil emulsions. An oil-in-water-in-oil emulsion is prepared from an oil-in-water emulsion that is subsequently dispersed in a second oil [73]. The second oil may contain a stabilizer, i.e., micron to sub-micron-sized solid particles, naphthenic acids, and asphaltenes.

751

752

CHAPTER 21 Dispersions, emulsions, and foams

21.2.4 MICROEMULSIONS A microemulsion is a thermodynamically stable fluid. It is different from kinetically stable emulsions which will be break into oil and water over time. The particle size of microemulsions ranges from about 10-300 nm. Because of the small particle sizes, microemulsions appear as clear or translucent solutions. The particle sizes of microemulsions may be identified by dynamic light scattering or neutron scattering. Microemulsions have ultralow interfacial tension (IFT) between the water phase and the oil phase. Water-in-oil microemulsions have been known to deliver water-soluble oilfield chemicals into subterranean rock formations. Also known are oil-in-alcohol microemulsions containing corrosion inhibitors in antifreeze compositions [74]. Microemulsions can be used to deliver a wide variety of oil soluble oilfield chemicals, including corrosion inhibitors, asphaltene inhibitors, scale inhibitors, etc. Thereby the amount of organic solvent needed is reduced. The microemulsion increases the dispersibility of oilfield chemicals into the produced fluids or pumped fluids. In this way, the performance of the particular chemical is increased [74]. Microemulsions may be broken by a variety of mechanisms, such as by chemicals or by temperature changes. However, the most simple way of breaking is by dilution. An example of a microemulsion that caries a corrosion inhibitor is listed in Table 21.2. The formulation in Table 21.2 can be easily diluted to the water phase. If the amount of toluene is increased in favor of water, a microemulsion is obtained that can be diluted by a hydrocarbon solvent. Still other examples are given elsewhere [74].

21.2.5 SOLIDS-STABILIZED EMULSION Emulsions can be stabilized using undissolved solid particles, which are partially oleophilic [75]. Three-phase emulsions that are stabilized with solids have been reviewed [76]. Further, the phenomenon of oil loss due to entrainment in emulsion sludge layers has been assessed. A semi-empirical approach has suggested for estimating the loss of oil. Table 21.2 Microemulsion with Corrosion Inhibitor [74] Component

Amount/[%]

Toluene Oleic imidazoline (corrosion inhibitor) Oleic acid (corrosion inhibitor) Dodecyl benzene sulfonic acid Ethanolamine Butyl alcohol Water

2 4 4 2 2 20 66

21.2 Emulsions

The solid particles may be either indigenous to the formation or obtained from outside the formation. Nonformation solid particles include clays, quartz, feldspar, gypsum, coal dust, asphaltenes, and polymers. Preferably, however, the particles contain small amounts of a ionic compound. Typically, the particles exhibits some composite irregular shape [75]. The solid particles should have either some oleophilic character for making an oil-external emulsion or some hydrophilic character for making a water-external emulsion. This property is important for ensuring that the particles can be wetted by the external continuous phase that holds the internal, discontinuous phase. The oleophilic or hydrophilic character may be an inherent characteristic of the solid particles or either acquired by a chemical treatment of the particles. For example, oleophilic fumed silicas, e.g., AerosilTM R972 or CAB-O-SILTM consist of small spheres of fumed silica that have been treated with organosilanes or organosilazanes to make the surfaces oleophilic. These are effective solids for stabilizing many crude oil emulsions. Such particles are extremely small, having primary particles consisting of spheres with diameters as small as about 10-20 nm, although the primary particles interact to form larger aggregates. These silicas are effective at concentrations of 0.5-20 g l−1 . Figure 21.4 shows the viscosity of an emulsion with solid particles at a shear rate of 75 s−1 as a function of the water content. The oil in the emulsion can be pretreated with a sulfonating agent prior to emulsification, in order to enhance its ability to make a solids-stabilized water-in-oil

Viscosity/[cP]

10,000

1000

100 0

FIGURE 21.4 Viscosity viz. water content.

10

20 30 40 Content of water/[%]

50

60

753

754

CHAPTER 21 Dispersions, emulsions, and foams

Table 21.3 Effect of Various Methods of Pretreatment of Crude Oil [78] Unsaturated

NSOa

Method

Saturated

Untreated Crude Oil Dye Sensitized Photochemically Treated Photochemically Treated Thermally Air Oxidized Biologically Oxidized

35.4 34.2

39.8 26.6

15.4 26.6

9.4 12.7

31.1 34.2 32.4

20.5 19.3 39.8

30.7 33.6 18.4

17.9 13.0 9.4

a Polycondensed

Compounds (%)

Asphaltene

aromatic benzene units with oxygen, nitrogen, and sulfur (NSO-compounds).

emulsion [77]. A specific procedure for the sulfonation of both the solids and the oil has been disclosed [77]: Preparation 21–1: The crude oil and the solid particles are co-sulfonated. Twelve grams g of crude oil and solids comprised of 0.06 g of 2-methylbenzyl tallow intercalated monomorillonite and 0.12 g of asphalt are stirred at 50 ◦ C for 72 h. Subsequently, concentrated sulfuric acid is added at 3 parts per 100 parts of oil at 50 ◦ C during 24 h.

In a variant of the preparation method 21–1, the sulfonated crude oil can be combined with a maleic acid grafted copolymer from ethylene and propylene [78]. In addition, instead of sulfonation, a photochemical treatment of the oil has been examined [78]. Hereby, a bentonite clay gel is mixed with the crude oil before photochemical treatment. In a dye sensitized photochemical treatment process, the crude oil is first mixed with Rhodamine-B. Rhodamine-B is a red dye that increases the quantum efficiency of the photochemical conversion of oil into oxidized products. In Table 21.3, the differences in change of the compositions of a crude oil by various methods of pretreatment is shown.

21.2.6 BIOTREATED EMULSION Another pretreatment method to enhance the stability of a water-in-oil emulsion consists in of biotreating the oil prior to emulsification. Water-in-oil emulsions made from a biotreated oil exhibits an enhanced stability. Oil-degrading microbes are used in the biotreatment process [78]. Preparation 21–2: For the biotreatment of the oil, the oil is placed into a bioreactor. Water in an 10- to 100-fold excess should be present in the reactor. Oil-degrading microbes, e.g., inoculum are then added to the reactor. Inoculum is a culture of microbes. The concentration of microbes in the inoculum can be measured by colony forming units. The oil-degrading microbes can be obtained from an oil waste water treatment facility.

21.2 Emulsions

Nutrients can be provided to feed the microbes. The nutrients will preferably contain nitrogen and phosphorous. The bioreactor is purged with air or oxygen. at a temperature of 20-70 ◦ C. After the biotreatment step, the biotreated oil can be separated from the aqueous phase of the bioreaction prior to forming a water-in-oil emulsion with the biotreated oil. However, it is preferred to form an emulsion using both the biotreated oil and the aqueous phase of the bioreaction as the aqueous phase contains components that will help further enhance the stability of the resulting water-in-oil emulsion.

It is believed that the biotreatment step promotes an enhanced stability of a waterin-oil emulsion according to the following mechanisms [78]: •

•

•

Some of the aliphatic components of oil are oxidized and polar ketones or acid functionality are introduced on the aliphatic chain. Organo sulfur compounds are also susceptible to oxidization and can form corresponding sulfoxides. The oxygenated compounds are more surface active than the aliphatic components themselves and thus contribute to improving the stability of the water-in-oil emulsion. If naphthenic acids are present as salts of divalent cations like calcium, biooxidation is likely to convert these salts to decarboxylated naphthenic hydrocarbons or lower carbon number naphthenic acids and the corresponding metal oxide. These constituents serve to enhance the stability of the water-in-oil emulsion. In the process of biotreating oil, the aqueous phase of the bioreaction also undergoes substantial changes. Upon completion of the bioreaction, the aqueous phase is a dispersion of biosurfactants, i.e., rhammanolipids produced by the microbes, and dead microbe cells. These components act synergistically to enhance the stability of water-in-oil emulsions. The aqueous phase of the bioreaction may therefore be used to make the water-in-oil emulsion, and serve to further enhance the stability of the resulting emulsion.

21.2.7 BIOCONCENTRATION FACTOR OF LINEAR ALCOHOL ETHOXYLATES Determination of the potential of surfactants to bioaccumulate in marine species has long been problematic in the chemical-hazard and environmental impact assessments performed for offshore operations [79]. Recently, this issue has become increasingly significant because regulators have invoked the precautionary principle and assume that all surfactants with molecular weight of less than 700 will bioaccumulate, leading to an increased number of oilfield-chemical products labeled as environmentally unacceptable. A method for estimating the bioconcentration potential from the octanol water partition coefficients has been presented already in 1983 [80]. The BCF is the most commonly used as indicator of its tendency to accumulate in aquatic organisms from the surrounding medium [81]. Because it is expensive to measure, the BCF

755

756

CHAPTER 21 Dispersions, emulsions, and foams

is generally estimated from the octanol/water partition coefficient, but currently used regression equations were developed from small data sets that do not adequately represent the wide range of chemical substances now subject to review. The relationship between the bioconcentration factor (BCF) of nonsurfactant substances and their corresponding octanol/water partition coefficient value is well studied, and many relationships have been developed. However, this methodology cannot be applied directly to surfactants because the formal octanol/water partition coefficient of such substances is difficult, if not impossible, to determine accurately. By their very nature, surfactants tend to form emulsions or accumulate at interfaces. Therefore, the standard OECD 107 cannot be used. A simple method for accurately determining the BCF of linear alcohol ethoxylates has been described [79]. Structure-activity relationships have been used to calculate a preliminary parameter. This hydrophobic parameter has been then correlated to BCF values determined in flow-through experiments, with an excellent agreement. This method involves no animal testing, is inexpensive to set up and perform, is accessible to all, quick and easy to use and verify, and gives clear results [79].

Partition coefficient ( n-octanol/water) using shake flask method The partition coefficient of n-octanol and water can be determined by OECD standards Test No. 107 and Test No. 117. The test guideline describes a method to determine experimentally Pow values in the range log Pow between -2 and 4 [82]. The method can not be used with surface active materials. The partition coefficient is defined as the ratio of the equilibrium concentrations of a dissolved substance in a two-phase system consisting of two largely immiscible solvents. There are three runs with different volume ratio of n-octanol to water. Duplicate vessels containing accurately measured amounts of the two solvents and stock solution are used in all three runs. After agitation the separation of the two phases, in general, is achieved by centrifugation. It is necessary to determine the concentrations of the test substance in both phases. Analytical methods which may be appropriate are: photometry, gas chromatography, and high performance liquid chromatography. The total quantity of substance present in both phases should be calculated and compared with the quantity originally introduced [82]. Also, the HPLC method permits to determine the partition coefficient n-octanol to water (Pow) [83].

High-pressure hydrocarbon systems In order to emulate the low interfacial tensions often experienced in high-pressure hydrocarbon systems, the use of carbon dioxide (CO2 ) as model fluid has been studied. It has been described, how the CO2 system behaves the conditions of saturation [84]. The results show that it is possible to obtain streams of droplets for droplet experiments. The mean diameter in the studied regime with the particular nozzle used was on the order of 100 µ m, while the smallest droplets possible to track with the presented technique were approximately 40 µ m.

21.2 Emulsions

21.2.8 SHALE INHIBITION In order to prevent bit balling and sloughing off of shale, it is necessary to provide shale stabilization. It is possible to provide shale stabilization by using a high concentration of an inorganic salt in the dispersed phase. Clay chemistry has shown that cationic base exchange with the negatively charged clay minerals commonly found in shale formations, limits their ability to hydrate, soften, and swell, thereby rendering them more stable in the presence of waterbased fluids and reducing or preventing screen blinding. Unfortunately, concentrated solutions of inorganic salts are toxic. As an alternative, organic amines have been proposed as shale inhibitors. These are selected from substituted or unsubstituted triethanolamines, diaminocyclohexanes, and hexamethylene diamines [85].

21.2.9 TRANSPORTATION Water-external emulsions can be transported in pipelines to achieve higher net flow rates of oil than in the transport of dry oil alone [86]. The percentage of oil in water may vary between 70 and 80%. The oil is combined with an aqueous solution comprising water, a pH enhancing agent, and solid particles and mixed until the solids-stabilized oil-in-water emulsion is formed. The pH of the resulting oil-in-water emulsion should be at 7.5-10. In propagating the emulsion through a pipe it is preferred to contact the inner walls of the pipe at first with a wettability altering agent to make the inner walls of the pipe water-wet so to facilitate the propagation of the oil-in-water emulsion. After contacting the inner walls of the pipe with the wettability altering agent, the oil-in-water emulsion can be pumped through the pipe. High-oil content, solids-stabilized oil-in-water emulsions are therefore good candidates for transportation in pipelines using flow regimes of either self-lubricating core annular flow or as uniform, lower-viscosity water-external emulsions [86]. In core annular flow, the formation of a low-viscosity annulus near the pipe wall, further reduces pressure drop. The viscosity of water, i.e., the continuous phase, is not greatly affected by temperature. Therefore, the viscosity of a solids-stabilized oil-in-water emulsions is not greatly affected by the temperature, and such oil-in-water emulsions do not have to be heated to high temperatures to maintain an acceptably low viscosity for economical transport. Another benefit of the oil-in-water emulsion is that the oil phase does not tend to wet the steel. Thus, these emulsions will have fewer tendencies to wet or foul the pipeline walls than oil-external emulsions or dry oil [86].

21.2.10 ACID-RICH OILS Crude oils produced from the North Sea, from the Far East, and from Western Africa exhibit high total acid numbers. In addition, they have high concentrations

757

758

CHAPTER 21 Dispersions, emulsions, and foams

of naphthenic acids [87]. Such crude oils may form calcium naphthenate precipitates or naphthenate stabilized emulsions. Naphthenates can act as natural surfactants leading either to stabilized emulsions or solid deposits following complexation with certain cations present in the aqueous phase. Naphthenate inhibitors include strong acids that protonate the rather weak naphthenic acids [87].

21.2.11 CHARACTERIZATION OF EMULSIONS Hansen solubility parameters For preparing emulsions and in general to estimate the miscibility, the Hansen solubility parameters may be useful [88, 89]. The Hansen solubility parameters are an extension of the Hildebrand solubility parameters [90]. For a certain molecule, three Hansen parameters are needed, which have a physical dimension as Pa1/2 , which is an energy density. The distance Ra of two solvents 1 and 2, δi = δi,1 − δi,2 between Hansen parameters is Ra2 = 4(δd )2 + (δp )2 + (δh )2

(21.1)

δd is the energy density from dispersion bonds between molecules, δp is the energy from dipolar intermolecular force between molecules, and δh is the energy from hydrogen bonds between molecules. Further, a radius of interaction R0 is needed. A pair of compounds is soluble, if Ra > 1. R0

The solubility parameter of a liquid mixture is proportional to the amount of each liquid assuming the two liquids are completely miscible. The solubility parameters can be determined by the measurement of the solubility, similar to the Hildebrand parameters. Several solvents are chosen and trials of the solubility of a substance with unknown Hansen solubility parameters are done. Another method of access of the solubility parameters is by inverse gas chromatography [91]. Solubility parameters are compiled in Perry’s standard tables [92]. Examples for the use of the Hansen solubility parameters in petroleum applications are presented elsewhere [93–95].

Micro-percolation test Unstable emulsions will eventually form two separate macroscopic phases, i.e., an oil emulsion phase and a water phase. The stability of an emulsion can be assessed by the flow through porous media in a rapid and convenient assay [78]. A sample of an emulsion that would pass completely through porous media can be centrifuged to form two distinct phases. The respective volumes can be used as a measure of the stability of an emulsion. The emulsion is as more unstable as is greater

21.2 Emulsions

the proportion of water that forms a clear phase after passing the porous medium and after subsequent centrifugation. The brine-breakout is defined as the fraction of the water or brine that is in the emulsion and that forms a distinct separate aqueous phase. The brine-breakout ranges between one, indicating completely unstable and zero, maximally stable. Details of the procedure have been presented elsewhere [78].

Field bottle test Oilfield emulsions are often characterized using the field bottle test [96]. This test has been used already in the 1950 [97]. Experimental details of this test have been described [98, 99]. However, the test is not standardized. So the bottle test does not strictly prescribe a procedure that can be used as such for studying all cases of emulsions [100]. Manning and Thompson have given the following procedure [99]. 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

get the sample in a 5 gal can with a screw cap. drain off all free water. shake the can and determine sediments and water of the emulsion. number the appropriate quantity of eight precipitation bottles. add 100 ml of emulsion, normal emulsion breaker and revers emulsion breakers to each bottle. heat to the treating temperature, place the bottles into a shaker and shake for 3 min. place into a thermostat and start the timer. after the required time, read the water breakout in each bottle. with a syringe remove some o the oil. analysis of the oil.

By coupling the data obtained from field bottle test and data that characterize the samples themselves, it is possible to gain insight into the factors that describe and are responsible for the stability of the emulsion. Since a lot of variables flow into the analysis, the method is considered as multivariate. A broad spectrum of oils has been characterized using 18 different parameters. Statistical analysis of the data sets has been performed. In order to predict the stability of an emulsion, it has been found that the solid content, but not the asphaltene content or any other crude oil parameter is the best single predictor for the stability of an emulsion. Statistical analysis reveals that the stability of an emulsion is most aptly described using several crude oil parameters, as opposed to one single factor [101, 102].

Separation index In order to characterize emulsions, the emulsion separation index has been developed. This index has been used for selecting and screening demulsifiers.

759

760

CHAPTER 21 Dispersions, emulsions, and foams

The fraction of the total water separated in a regular bottle test using different demulsifier dosages is averaged to determine a separation index. The separation index ranges from zero with no separation up to 100%, which indicates full separation. So the separation yields a measure of the stability of an emulsion. As lower the index, as greater is the tightness or stability of the emulsion. The conditions of test must be given, i.e., in particular the temperature of testing and the nature of demulsifier system. Details, how to conduct a separation test have been given by Kokal [63]. Procedure 21–3: After delivery of the crude oil sample in the laboratory, the samples are remixed with a standard bottle shaker for 1 min. The sample is added to 100 ml standard centrifuge tubes, which are placed into a water bath to reach the desired temperature for 30 min. Then, the chemical to be tested (demulsifier) is added to the centrifuge tubes. The tubes are shaken and again placed in the water bath. After some predefined time intervals, e.g., 5, 10, 15, 20 min, the amount of water separated is controlled. After 20 min the tubes are centrifuged and the final amount of water separated is measured.

The emulsion separation index I is then calculated by  I=

w × 100. wf n

(21.2)

Here, w is the water separation at a given demulsifier concentration as the percentage of basic sediment and water after a certain time interval, i.e., it runs from 5, 10, 15, 20 min and final wf . n is the number of readings of the water content, here totally 5, i.e., reading after 5, 10, 15, 20 min and final wf . Examples how to evaluate the emulsion separation index have been presented [63]. Using the separation index, the effect of various factors can be elucidated that affect the oil-water separation, including • • • • • •

temperature, shear, asphaltene content, watercut, demulsifier dosage, and mixing different crude oil types.

The use of the emulsion separation index has in fact eliminated some of the previous mysterious art associated with the selection of a demulsifier and diagnosing emulsion treatment problems. Field case studies have been described, where the emulsion separation index was used to select the best demulsifier, diagnose, and ultimately solve emulsion related problems during oil production. The results show a strong correlation of asphaltene content in the crude oil with emulsion separation index or emulsion tightness. Recommendations can be made for reducing and optimizing the dosage of the demulsifier by adding other chemicals [62].

21.2 Emulsions

Differential scanning calorimetry Differential scanning calorimetry (DSC) is generally used to determine the composition of water-in-oil emulsions, as it can distinguish free water from emulsified water [103, 104]. Namely, free water crystallizes at higher temperatures than water droplets in the emulsion. This technique is based on the solidification and melting properties of droplets and of the medium in which they are dispersed. The data obtained DSC give information about [66]: • • • • •

the type of emulsion: simple (water-in-oil or oil-in-water) or multiple (water-in-oil-in-water, or oil-in-water-in-oil respectively), the quantity of liquid and its state: bound or dispersed or free, the compositions of the free and dispersed forms, the mean diameter of the droplets and their evolution with time due to coalescence or Ostwald ripening, and matter transfers between droplets due to their compositional differences.

Stability of invert emulsions Stability of Invert Emulsions can be tested according by the following procedures [85]: Procedure 21–4: A small portion of the emulsion is placed in a beaker which contains an oleaginous fluid. If the emulsion is an invert emulsion, the small portion will disperse in the oleaginous fluid. Visual inspection determines whether the small portion added has dispersed.

The electrical stability of the invert emulsion can be tested as follows: Procedure 21–5: A voltage is applied across two electrodes immersed in the emulsion, and the voltage is increased until the emulsion breaks and a surge of current flows between the two electrodes. The voltage required to break the emulsion is a common measure of the stability of an emulsion.

21.2.12 LOW-FLUORESCENT EMULSIFIERS Citric acid-based poly(amide) (PA) type emulsifiers for drilling applications have been developed that exhibit a very low fluorescence. PAs are conventionally prepared by first reacting a fatty acid with diethylene triamine in order to form the amide. Afterwards the amide is reacted with citric acid. These products exhibit a relatively high fluorescence. The reaction is shown in Figure 21.5. On the other hand, a PA with pendent citric acid units can be made via a cyclic intermediate, an imidazoline structure. This is followed by ring opening to yield an isomeric amide. The reaction is shown in Figure 21.6.

761

762

CHAPTER 21 Dispersions, emulsions, and foams

O H2N

R C

CH2

CH2

OH

N

CH2

CH2

NH2

H

O C R

HO

O

O

C R

R C N

CH2

CH2

H

N CH2

CH2

H

N H

O

OH

HO

O OH

O

OH O

O

C R

R C N

CH2

H

CH2

N CH2

O

O HO

CH2

N H

OH O OH

FIGURE 21.5 Conventional synthesis of poly(amide) surfactants [105].

The products synthesized via the reaction shown in Figure 21.6 exhibit a much lower fluorescence. Discharged fluids having low fluorescence are less likely to impart a sheen to the ocean’s surface [105]. In this way, discharge operations will become less obvious.

21.3 FOAMS A foam is a liquid with gas cells enclosed. The first scientist deeply engaged with foams was Joseph A. F. Plateau, whose monograph appeared in 1783 [106]. Foams find use in • • • • •

foam drilling, foam cementing, foam flooding, Foam-based fracturing, and water shutoff.

21.3 Foams

O H2N

R C

CH2

CH2

N CH2

OH

CH2

NH2

H

O C R

HO

O

O

C R

R C N

CH2

CH2

N CH2

H

CH2

N

H

H

O C R N CH2

N

CH2

N H

R O

OH

HO

OH

O

OH

O

O

R C

H N O

CH2

CH2

C R

N CH2

CH2

N H

O HO

O

OH O OH

FIGURE 21.6 Synthesis of poly(amide) surfactants via imidazoline [105].

According to thermodynamics, in a spherical bubble there is an excess pressure p, which is related according to the law of Young to the radius r and the surface tension σ as p =

σ . r

(21.3)

763

764

CHAPTER 21 Dispersions, emulsions, and foams

21.3.1 APHRONS An aphron is a phase that is surrounded by a tenside like film, e.g., a soap bubble. The term originates from the Greek αφρoσ for foam. The topic has been described by Sebba, who obviously coined the term [107, 108]. Aphrons have been also termed as biliquid foams. In short, an aphron is a foam, where the liquid skin is built up from two phases. So, in contrast to a conventional air bubble, which is stabilized by a surfactant monolayer, the outer shell of an aphron consists of a much more robust surfactant tri-layer. Colloidal gas aphrons as proposed by Sebba are made up from a gaseous inner core surrounded by a thin aqueous surfactant film composed of two surfactant layers. In addition, there is a third surfactant layer that stabilizes the structure [109]. The basic structure of a colloidal gas aphron is shown in Figure 21.7. The aphron includes a spherical core, which is usually a gas. This gas is encapsulated in a thin shell. This shell contains surfactant molecules. The surfactants point with their hydrophobic, i.e., nonpolar ends into the gas core. The hydrophilic ends point into a second phase, that may be water that contains a thickening agent and an aphron stabilizer. In addition, the second phase contains surfactant molecules at the outer boundary. These molecules are pointing with their hydrophobic ends into the third outer phase. The third phase also contains an additional layer of surfactant molecules whose hydrophilic ends extend into the bulk fluid.

Core

Shell

Double layer

Bulk phase

FIGURE 21.7 Basic structure of an aphron [109].

: Surfactant

21.3 Foams

Thus, the surrounding phase is a bilayer of surfactant molecules, which serves as an effective barrier to coalescence with adjacent aphrons. It is believed that the exterior surfactant layer is not strongly associated with the rest of the aphron that may be shed when aphrons come into contact with each other so that they agglomerate rather than coalesce. The surfactant molecules are not necessarily built up from the same material. In other words, each surfactant layer may be comprised of different types of surfactants [110]. Colloidal gas aphrons are of interest, because they [109]: • • • •

have a comparatively large interfacial area, exhibit a relatively high stability, show similar flow properties to those of pure water, and can be easily separated from the bulk liquid phase.

Aphrons can survive a compression to at least 27.3 M Pa (4000 psig), whereas conventional bubbles do not survive pressures much higher than a tenth of that [111]. An apparatus for investigating the survivability of aphron bubbles under high pressure has been designed [112, p. 35]. Two viewing cells simultaneously record the size and the concentration of bubbles before and after filtration through a sintered metal filter. Aphrons are of importance in fluids used for oilfield applications [111, 113]. The first use of aphrons in a drilling fluid application has been described in 1998 [114]. When a drilling fluid migrates into a loss zone, aphrons move faster than the surrounding liquid phase and quickly form a layer of bubbles at the front of the fluid. This bubble front and the radial flow pattern of the fluid rapidly reduce the shear rate and raise the fluid viscosity, resulting in diminishing the invasion of the fluid. Further, aphrons exhibit only little affinity for each other or for the mineral surfaces of the pores or fractures. Consequently, the sealings which they form are soft. Their lack of adhesion enables them to be flushed out easily whenever desired [111]. The aphrons reduce the density of a drilling fluid and provide bridging and sealing of the formations contacted by the fluid as the bubbles expand to fill the openings exposed while drilling. Low shear rate polymers strengthen the microbubbles and act as fluid loss agents [115]. In this way, lost circulation is prevented. Moreover, the IFT between the base fluid and produced oils or gases is low. So the fluids have no tendency to formation damage. Depleted wells, which are very expensive to drill underbalanced or with other remediation techniques, have been drilled overbalanced with the aid of aphron drilling fluids [111]. In a foam of the water-lamella type small globules of oil are encapsulated in a surfactant-stabilized film and separated from one another by a further thin lamella of water. Biliquid foams are essentially of two types [107]: • •

oil lamella and water lamella.

An oil lamella biliquid foam consists of aqueous cells coated with an oil film and separated one from another by an oil lamella. In this type, the oil phase corresponds to

765

766

CHAPTER 21 Dispersions, emulsions, and foams

the aqueous phase in a conventional gas foam, and the water globules correspond to the gas cells. The second type of biliquid foam is one in which the discontinuous phase is the oil or a nonpolar liquid and the encapsulating phase is water or a hydrogen-bonded liquid which contains a soluble surfactant. The encapsulating film as well as the foam lamella are stabilized by the surfactant. In both types, the cells are held together by capillary pressures, just as are the soap bubbles in a gas foam. A water-lamella biliquid foam must be distinguished from oil-in-water emulsions in which the discontinuous oil phase is separated from the continuous aqueous phase by a single interface. At moderate gas concentrations, the stability of bubbles in an aqueous medium depends primarily on the viscosity of the bulk fluid and the IFT. More specifically, the stability is determined by the rate of mass transfer between the viscous water shell and the bulk phase. This transfer is known as Marangoni convection [116]. Carlo Marangoni, published his results in 1865 in the course of his doctoral thesis at the University of Pavia. If, by some disturbing effects, e.g. a temperature gradient, a gradient in the surface tension is locally induced, a convection or movement of liquid will occur. Thus, the Marangoni convection contributes to the decomposition of foams. If the mass transfer rate is high, aphrons will become unstable. Therefore, the shell fluid must be designed to have certain viscosity to minimize the Marangoni effect [116]. Bulk viscosity is generally controlled by the addition of polymers and clays. The IFT is usually lowered with a surfactant. In contrast to a typical bubble, an aphron is stabilized by a very high interfacial viscosity of the second phase [115]. Fluids with a low share rate viscosity are helpful in controlling the invasion of a filtrate by creating an impermeable layer close to the formation openings. Since the fluid moves at a very slow rate, the viscosity becomes very high, and the depth of invasion of the fluid into the formation is kept shallow. Specific aphron stabilizers are PVA in combination with surfactants, such as cocamidopropyl betaine or an alkyl ether sulfate [110]. The aphron stabilizer modifies the viscosity of the water layer to such an extent that it creates an elastomeric membrane. This elastomeric membrane allows the aphrons to display an improved stability and sealing capability. The surfactants required to create the aphrons must be compatible with the polymers present in the fluid to create the desired low shear rate viscosity. Therefore, the surfactants will generally be of the non-ionic or anionic type [115]. A series of surfactants have been screened using a low pressure API filtration cell [117]. Test procedure 21–6: The cylindrical body of the cell is made from plexiglas of a thickness 0.5 in (1.3 cm). Two hundred grams of sand is added with a particle size of 50-70 mesh (210-297 µm). In this way, a sand bed depth of 2.1 cm is obtained. No filter paper is used in the cell. 350 ml of the fluid to be tested is slowly added to the cell, the cell assembled, and a pressure of nitrogen of 0.7 M Pa (100 psi) is applied. The pressure is released after the nitrogen blows through the bed for 30 s. Upon releasing the pressure the sand bed will expand in height as the bubbles in the sand bed expand. The average

References

Table 21.4 Average Increase of the Height of a Sand Bed Using API RP 13B-1 [115] Surfactant

Increase/[%]

Sodium dioctyl sulfosuccinate Chubb national foam-high expansion Alpha olefin sulfonate Ethoxylated 2,4,7,9-tetramethyl-5-decyn-4-diol Linear C9 –C11 alcohol ethoxylates, 6 mol EO/mol Tetrasodium N-(1,2-dicarboxyethyl)-N-octadecyl sulfosuccinate Mixture of diethanolamides of fatty acids Sodium disopropyl naphthalene sulfonate Linear C12 –C15 alcohol ethoxylates, 7 mol EO/mol Modified alkyl ether sulfate Ethoxylated octadecylamine-octadecylguanidine complex Ethoxylated (20 moles) methyl glucoside sesquistearate 2,4,7,9-Tetramethyl-5-decyne-4,7-diol Ethoxylated nonyl phenol Sodium alkyl sulfate Poly(oxypropylene)-poly(oxyethylene) block copolymer

118.8 96.4 63.7 56.0 56.0 50.6 50.0 38.1 38.1 28.6 19.0 19.0 <10 <10 <10 <10

increase in height of the bed is measured. Surfactants which increase the sand bed by at least 50% are considered to be preferred for the generation of aphrons [115].

The average percent increase in height of the sand bed is given in Table 21.4, tested according to test procedure 21–6. The effects of polymer and surfactant concentration, surfactant type, shear rate, mixing time and water quality on the bubble size of colloidal gas aphrons have been studied [116]. Several other tests suitable to characterize aphrons have been described in detail, including [112]: • • • •

survivability of bubbles under high pressure, disk leak-off test, syringe sand pack leak-off test, and capillary flow test.

REFERENCES [1] Wikipedia. Dispersion (chemistry) — Wikipedia, The Free Encyclopedia. Disp: 10, http://en.wikipedia.org/w/index.php?title=Dispersion_(chemistry)&oldid=646118714; 2015 [accessed 23.04.15]. [2] Ian D. Morrison SR. Colloidal dispersions: suspensions, emulsions, and foams. New York: Wiley-Interscience; 2002.

767

768

CHAPTER 21 Dispersions, emulsions, and foams

[3] Bibette J, Leal-Calderon F, Schmitt V, Poulin P. Emulsion science: basic principles, an overview; Springer tracts in modern physics, vol. 186. Berlin: Springer; 2002. [4] MacKay RB, editor. Technological applications of dispersions; Surfactant science series, vol. 52. New York: Dekker; 1994. [5] Weaire D, Hutzler S. The physics of foams. Oxford: Clarendon Press; 1999. [6] Tadros TF. Industrial applications of dispersions. Adv Colloid Interface Sci 1993;46:1-47, doi:10.1016/0001-8686(93)80032-7. [7] Endo Y, Kousaka Y. Dispersion mechanism of coagulated particles in liquid flow. Colloids Surf A 1996;109:109-15, doi:10.1016/0927-7757(95)03478-1. [8] Bergenholtz J. Theory of rheology of colloidal dispersions. Cur Opin Colloid Interface Sci 2001;6(5-6):484-8, doi:10.1016/S1359-0294(01)00112-1. [9] Yaghmur A, Glatter O. Characterization and potential applications of nanostructured aqueous dispersions. Adv Colloid Interface Sci 2009;147-148:333-42, doi: 10.1016/j.cis.2008.07.007. [10] Conley RF. Practical dispersion: a guide to understanding and formulating slurries. Weinheim: Wiley VCH; 1996. [11] Burrafato G, Carminati S. Aqueous drilling muds fluidified by means of zirconium and aluminium complexes, EP patent 623 663, assigned to Eniricerche SPA and Agip SPA; 1994. URL: https://www.google.com/patents/EP623663. [12] Burrafato G, Carminati S. Aqueous drilling muds fluidified by means of zirconium and aluminum complexes, CA patent 2 104 134; 1994. URL: https://www.google.com/ patents/CA2104134. [13] Burrafato G, Carminati S. Aqueous drilling muds fluidified by means of zirconium and aluminum complexes. US patent 5 532 211; 1996. URL: http://www.freepatentsonline. com/5532211.html. [14] Burrafato G, Gaurneri A, Lockhart TP, Nicora L. Zirconium additive improves field performance and cost of biopolymer muds. SPE oilfield chem. int. symp. (Houston, 2/18-21/97); 1997, p. 707-10. doi:10.2118/37288-MS. [15] Hale AH, Lawson HF. Well drilling fluids and process for drilling wells. US patent 4 740 318; 1988. URL: http://www.freepatentsonline.com/4740318.html. [16] Hale AH, Rivers GT. Well drilling fluids and process for drilling wells. US patent 4 721 576; 1988. URL: http://www.freepatentsonline.com/4721576.html. [17] Hale AH. Well drilling fluids and process for drilling wells. US patent 4 728 445; 1988. URL: http://www.freepatentsonline.com/4728445.html. [18] Lawson HF, Hale AH. Well drilling fluids and process for drilling wells, US patent 4 812 244; 1989. URL: http://www.freepatentsonline.com/4812244.html. [19] Peiffer DG, Bock J, Elward-Berry J. Zwitterionic functionalized polymers as deflocculants in water based drilling fluids. US patent 5 026 490, assigned to Exxon Research & Eng. Co.; 1991. URL: http://www.freepatentsonline.com/5026490.html. [20] Peiffer DG, Bock J, Elward-Berry J. Thermally stable hydrophobically associating rheological control additives for water-based drilling fluids. US patent 5 096 603, assigned to Exxon Research & Eng. Co.; 1992. URL: http://www.freepatentsonline. com/5096603.html. [21] Peiffer DG, Bock J, Elward-Berry J. Zwitterionic functionalized polymers. GB patent 2 247 240, assigned to Exxon Research & Eng. Co.; 1992. URL: http://www. directorypatent.com/GB/2247240-a.html. [22] Peiffer DG, Bock J, Elward-Berry J. Zwitterionic functionalized polymers as deflocculants in water based drilling fluids, CA patent 2 046 669, assigned to Exxon Research & Eng. Co.; 1992. URL: https://www.google.com/patents/CA2046669.

References

[23] Peiffer DG, Bock J, Elward-Berry J. Thermally stable hydrophobically associating rheological control additives for water-based drilling fluids. CA patent 2 055 011, assigned to Exxon Research & Eng. Co.; 1993. URL: https://www.google.com/patents/ CA2055011. [24] Peiffer DG, Bock J, Elward-Berry J. Zwitterionic functionalized polymers as deflocculants in water based drilling fluids, AU patent 638 917, assigned to Exxon Research & Eng. Co.; 1993. [25] Grey RA. Process for preparing alternating copolymers of olefinically unsaturated sulfonate salts and unsaturated dicarboxylic acid anhydrides. US patent 5 210 163, assigned to Arco Chemical Technol. Inc.; 1993. URL: http://www.freepatentsonline. com/5210163.html. [26] Portnoy RC. Anionic copolymers for improved control of drilling fluid rheology, GB patent 2 174 402, assigned to Exxon Chemical Patents In; 1986. URL: http://www. directorypatent.com/GB/2174402-a.html. [27] Portnoy RC. Anionic copolymers for improved control of drilling fluid rheology, US patent 4 680 128; 1987. URL: http://www.freepatentsonline.com/4680128.html. [28] Farrar D, Hawe M, Dymond B. Use of water soluble polymers in aqueous drilling or packer fluids and as detergent builders, EP patent 182 600, assigned to Allied Colloids Ltd.; 1992. URL: https://www.google.com/patents/EP182600. [29] Giddings DM, Fong DW. Calcium tolerant deflocculant for drilling fluids, US patent 4 770 795; 1988. URL: http://www.freepatentsonline.com/4770795.html. [30] Garvey CM, Savoly A, Weatherford TM. Drilling fluid dispersant, US patent 4 711 731; 1987. URL: http://www.freepatentsonline.com/4711731.html. [31] McCallum TFI, Weinstein B. Amine-thiol chain transfer agents. US patent 5 298 585, assigned to Rohm & Haas Co.; 1994. URL: http://www.freepatentsonline.com/ 5298585.html. [32] Chadwick RE, Phillips BM. Preparation of ether carboxylates. EP patent 633 279, assigned to Albright & Wilson Ltd.; 1995. URL: https://www.google.com/patents/ EP633279. [33] Just EK, Nickol RG. Phosphated, oxidized starch and use of same as dispersant in aqueous solutions and coating for lithography. EP patent 319 989; 1989. URL: https:// www.google.com/patents/EP319989. [34] Szablikowski K, Lange W, Kiesewetter R, Reinhardt E. Easily dispersible blends of reversibly crosslinked and uncrosslinked hydrocolloids, with aldehydes as crosslinker (abmischungen von mit aldehyden reversibel vernetzten hydrokolloidmischungen und unvernetzten hydrokolloiden mit verbessertes dispergierbarkeit). EP patent 686 666, assigned to Wolff Walsrode AG; 1995. URL: https://www.google.com/patents/ EP686666. [35] Rooney P, Russell JA, Brown TD. Production of sulfonated asphalt, US patent 4 741 868; 1988. URL: http://www.freepatentsonline.com/4741868.html. [36] Cronje IJ. Process for the oxidation of fine coal. EP patent 298 710, assigned to Council Sci & Ind. Researc; 1989. URL: https://www.google.com/patents/EP298710. [37] Baret JF, Drecq P. Additives for oilfield cements and corresponding cement slurries. EP patent 314 242, assigned to Pumptech NV; 1989, URL: https://www.google.com/ patents/EP314242. [38] Baret JF, Drecq P. Dispersant for oil-well cement slurries and corresponding slurries (dispersant pour laitiers de ciment petroliers, et laitiers correspondants). FR patent 2 622 572; 1989. URL: http://www.directorypatent.com/FR/2622572-a1.html.

769

770

CHAPTER 21 Dispersions, emulsions, and foams

[39] Baret JF, Drecq P. Dispersant for oilfield cement slurries and corresponding slurries (dispersant pour laitiers de ciment petroliers, et laitiers correspondants). FR patent 2 635 469; 1990. URL: http://www.directorypatent.com/FR/2635469a1.html. [40] Crema SC, Kucera CH, Gousetis C, Oppenlaender K. Cementing compositions containing polyethyleneimine phosphonate derivatives as dispersants. EP patent 444 542, assigned to BASF Corp.; 1991, URL: https://www.google.com/patents/ EP444542. [41] Eoff L. Acetone/formaldehyde/cyanide resins, US patent 5 290 357, assigned to Halliburton Co.; 1994. URL: http://www.freepatentsonline.com/5290357.html. [42] Eoff L. Dispersant for cement in water. EP patent 604 000; 1994. URL: https://www. google.com/patents/EP604000. [43] Hendriks H. Dispersing agent for cement-slurry compounds, compounds containing this agent and procedures for the cementing of oil wells or similar (dispersant pour compositions de laitiers de ciment, compositions le contenant et procedes correspondants de cimentation de puits petroliers ou analogues). FR patent 2 620 442; 1989. URL: http:// www.directorypatent.com/FR/2620442-a1.html. [44] Hendriks H. Dispersing agent for cement-slurry compounds, compounds containing this agent and procedures for the cementing of oil wells or similar. EP patent 307 997, assigned to Pumptech NV; 1989. URL: https://www.google.com/patents/EP307997. [45] Patel B, Stephens M. Well cement slurries and dispersants therefor, US patent 5 041 630; 1991. URL: http://www.freepatentsonline.com/5041630.html. [46] Patel BB, Stephens M. Well cement slurries and dispersants therefor, US patent 4 923 516; 1990. URL: http://www.freepatentsonline.com/4923516.html. [47] Detroit WJ. Oil well drilling cement dispersant. US patent 4 846 888, assigned to Reed Lignin Inc.; 1989. URL: http://www.freepatentsonline.com/4846888.html. [48] Leighton JC, Sanders MJ. Water soluble polymers containing allyloxybenzenesulfonate monomers. EP patent 271 784; 1988. URL: https://www.google.com/patents/ EP271784. [49] Leighton JC, Sanders MJ. Water soluble polymers containing allyloxybenzenesulfonate monomers. US patent 4 892 898; 1990. URL: http://www.freepatentsonline.com/ 4892898.html. [50] Bloys JB, Wilson WN, Malachosky E, Bradshaw RD, Grey RA. 1994. Dispersant compositions comprising sulfonated isobutylene maleic anhydride copolymer for subterranean well drilling and completion, US patent 5 360 787, assigned to Atlantic Richfield Co.; 1994. URL: http://www.freepatentsonline.com/5360787.html. [51] Bloys JB, Wilson WN, Malachosky E, Carpenter RB, Bradshaw RD. Dispersant compositions for subterranean well drilling and completion. EP patent 525 037; 1993, URL: https://www.google.com/patents/EP525037. [52] Bouchut P, Kensicher Y, Rousset J. Non-polluting dispersing agent for drilling fluids based on freshwater or salt water. US patent 5 099 928; 1992. URL: http://www. freepatentsonline.com/5099928.html. [53] Bouchut P, Rousset J, Kensicher Y. A non-polluting dispersing agent for drilling fluids based on freshwater or salt water. AU patent 590 248; 1989. [54] Bouchut P, Rousset J, Kensicker Y. Non-polluting fluidizing agents for drilling fluids having soft or salt water base (agent fluidifiant non polluant pour fluides de forage a base d’eau douce ou saline), CA patent 1 267 777; 1990. URL: https://www.google. com/patents/CA1267777.

References

[55] Emmons DH. Sulfur deposition reduction. US patent 5 223 160; 1993. URL: http:// www.freepatentsonline.com/5223160.html. [56] Banavali RM, Chheda BD, Manari GM. Formulations useful as asphaltene dispersants in petroleum products. US patent 7 674 365, assigned to Rohm and Haas Company (Philadelphia, PA); 2010. URL: http://www.freepatentsonline.com/7674365.html. [57] Stephenson WK, Kaplan M. Asphaltene dispersants-inhibitors. CA patent 2 029 465, assigned to Nalco Chemical Co.; 1991, URL: https://www.google.com/patents/ CA2029465. [58] Lessard RR, DeMarco G. The significance of oil spill dispersants. Spill Sci Technol Bull 2000;6(1):59-68, doi:10.1016/S1353-2561(99)00061-4. [59] Chapman H, Purnell K, Law RJ, Kirby MF. The use of chemical dispersants to combat oil spills at sea: a review of practice and research needs in europe. Mar Pollut Bull 2007;54(7):827-38, doi:10.1016/j.marpolbul.2007.03.012. [60] Riley P. Compositions and methods for dispersing and biodegrading spilled petroleum oils and fuels, US patent 5 753 127, assigned to Petrotech AG; 1998. URL: http://www. freepatentsonline.com/5753127.html. [61] Kirby MF, Law RJ. Accidental spills at sea - Risk, impact, mitigation and the need for co-ordinated post-incident monitoring. Mar Pollut Bull 2010;60(6):797-803, doi: 10.1016/j.marpolbul.2010.03.015. [62] Kokal SL, Wingrove M. Emulsion separation index: from laboratory to field case studies. (63165-MS), SPE annual technical conference and exhibition, 1-4 October 2000; Dallas, Tx: Society of Petroleum Engineers; 2000. doi:10.2118/63165-MS. [63] Kokal SL. Crude oil emulsions. vol. I, chap. 12, Richardson, TX: Society of Petroleum Engineers; 2006. p. 533-70. [64] Taylor RS, Funkhouser GP, Dusterhoft RG. Gelled invert emulsion compositions comprising polyvalent metal salts of an organophosphonic acid ester or an organophosphinic acid and methods of use and manufacture, US patent 7 534 745, assigned to Halliburton Energy Services, Inc. (Duncan, OK); 2009. URL: http://www.freepatentsonline.com/ 7534745.html. [65] Jones TA, Wentzler T. Polymer hydration method using microemulsions, US patent 7 407 915, assigned to Baker Hughes Incorporated (Houston, TX); 2008. URL: http:// www.freepatentsonline.com/7407915.html. [66] Audibert-Hayet A, Giard-Blanchard C, Dalmazzone C. Organic emulsion-breaking formula and its use in treating well bores drilled in oil-base mud, US patent 7 226 896, assigned to Institut Francais du Petrole (Rueil Malmaison Cedex, FR); 2007. URL: http://www.freepatentsonline.com/7226896.html. [67] Xiang T. Invert emulsion drilling fluid systems comprising an emulsified aqueous phase comprising dispersed integral latex particles. US patent 7 749 945, assigned to Baker Hughes Incorporated (Houston, TX); 2010. URL: http://www.freepatentsonline.com/ 7749945.html. [68] Sawdon CA, Ballard DA. Wellbore fluid. GB patent 2 309 240, assigned to Sofitech NV; 1997. URL: http://www.lens.org/lens/patent/GB_2309240_A. [69] Monfreux-Gaillard N, Perrin P, LaFuma F, Sawdon C. Reversible emulsions stabilized by amphiphilic polymers and application to drilling fluid. US patent 7 262 152, assigned to M-I L.L.C. (Houston, TX); 2007. URL: http://www.freepatentsonline.com/7262152. html. [70] Lochhead RY, Rulison CJ. An investigation of the mechanism by which hydrophobically modified hydrophilic polymers act as primary emulsifiers for oil-in-wa-

771

772

CHAPTER 21 Dispersions, emulsions, and foams

[71]

[72]

[73]

[74]

[75]

[76]

[77]

[78]

[79] [80]

[81]

[82] [83] [84]

[85]

ter emulsions 1. Poly(acrylic acids) and hydroxyethyl celluloses. Colloids Surf A 1994;88(1):27-32, doi:10.1016/0927-7757(94)80082-0. Mueller H, Kirsner J, Burrows K. Thinners for invert emulsions, US patent 7 638 466, assigned to Halliburton Energy Services, Inc. (Duncan, OK); 2009. URL: http://www. freepatentsonline.com/7638466.html. Sullivan PF, Tustin GJ, Christanti Y, Kubala G, Drochon B, Hughes TL. Aqueous two-phase emulsion gel systems for zone isolation. US patent 7 703 527, assigned to Schlumberger Technology Corporation (Sugar Land, TX); 2010. URL: http://www. freepatentsonline.com/7703527.html. Varadaraj R. 2010. Oil-in-water-in-oil emulsion. US patent 7 652 074, assigned to ExxonMobil Upstream Research Company (Houston, TX); 2010. URL: http://www. freepatentsonline.com/7652074.html. Yang J, Jovancicevic V. Microemulsion containing oil field chemicals useful for oil and gas field applications. US patent 7 615 516, assigned to Baker Hughes Incorporated (Houston, TX); 2009. URL: http://www.freepatentsonline.com/7615516.html. Bragg JR. Oil recovery method using an emulsion. US patent 6 068 054, assigned to Exxon Production Research Co.; 2000. URL: http://www.freepatentsonline.com/ 6068054.html. Menon VB, Wasan DT. Characterization of oil-water interfaces containing finely divided solids with applications to the coalescence of water-in-oil emulsions: a review. Colloids Surfaces 1988;29(1):7-27, doi:10.1016/0166-6622(88)80169-0. Varadaraj R, Bragg JR, Dobson MK, Peiffer DG, Huang JS, Siano DB, et al. Solidsstabilized water-in-oil emulsion and method for using same. US patent 6 734 144, assigned to ExxonMobil Upstream Research Company (Houston, TX); 2004. URL: http://www.freepatentsonline.com/6734144.html. Varadaraj R, Bragg JR, Peiffer DG, Elspass CW. Stability enhanced water-in-oil emulsion and method for using same, US patent 7 186 673, assigned to ExxonMobil Upstream Research Company (Houston, TX); 2007. URL: http://www.freepatentsonline. com/7186673.html. Fraser G. Method for determining the bioconcentration factor of linear alcohol ethoxylates. SPE Prod Oper 2011;26(3), doi:10.2118/123846-pa. Veith GD, Kosian P. Estimating bioconcentrationpotential from octanol/water partition coefficients. In: Mackay D, Paterson S, Eisenreich SJ, Simons MS, editors. Physical Behavior of PCBs in the Great Lakes. Ann Arbor, Michigan: Ann Arbor Sciences Publishers; 1983. p. 269-82. Meylan WM, Howard PH, Boethling RS, Aronson D, Printup H, Gouchie S. Improved method for estimating bioconcentration/bioaccumulation factor from octanol/water partition coefficient. Environ Toxicol Chem 1999;18(4):664-72, doi: 10.1002/etc.5620180412. OECD . Test no. 107: Partition coefficient (n-octanol/water): shake flask method. OECD Report 107, 2004. doi:10.1787/9789264069626-en. OECD . Test no. 117: Partition coefficient (n-octanol/water), HPLC method. OECD Report 117, 2004. doi:10.1787/9789264069824-en. Dupuy PM, Fernandino M, Svendsen H, Westra R. CO2 : one-component two-phase system as model fluid for high-pressure hydrocarbon systems. SPE J 2011;16(2):482-8. doi:10.2118/139606-pa. Summerhill JL, Jarrett MA, McKellar AJ, Young DB, Grover PE, Gusler WJ. Organofunctional compounds for shale stabilization of the aqueous dispersed phase of non-aqueous based invert emulsion drilling system fluids. US patent 7 067 460,

References

[86]

[87]

[88]

[89] [90] [91]

[92] [93]

[94] [95]

[96] [97]

[98] [99] [100] [101] [102] [103] [104]

assigned to Baker Hughes Incorporated (Houston, TX); 2006. URL: http://www. freepatentsonline.com/7067460.html. Bragg JR, Varadaraj R. Solids-stabilized oil-in-water emulsion and a method for preparing same. US patent 7 121 339, assigned to ExxonMobil Upstream Research Company (Houston, TX); 2006. URL: http://www.freepatentsonline.com/7121339.html. Ubbels SJ. Methods for inhibiting naphthenate salt precipitates and naphthenatestabilized emulsions. US patent 7 776 930, assigned to Champion Technologies, Inc. (Houston, TX); 2010. URL: http://www.freepatentsonline.com/7776930.html. Hansen CM. The three dimensional solubility parameter – key to paint component affinities. I: Solvents, plasticizers, polymers and resins. J Paint Technol 1967;39(505):104-17. URL: http://www.hansen-solubility.com/Contents/HSP1967OCR.pdf. Hansen C. Hansen solubility parameters: a user’s handbook. 2nd ed. Boca Raton, FL: CRC Press; 2007. Burke J. Solubility parameters: theory and application. AIC Book and Paper Group Annual 1984;3:13-58. ([electronic:] http://cool.conservation-us.org/byauth/burke/solpar/). Adamska K, Bellinghausen R, Voelkel A. New procedure for the determination of hansen solubility parameters by means of inverse gas chromatography. J Chromatogr A 2008;1195(1-2):146-9, doi:10.1016/j.chroma.2008.05.020. Speight JG. Solubility parameters. 324 pp., New York: McGraw-Hill; 2004. Frost KA, Daussin RD, Domelen MSV. New, highly effective asphaltene removal system with favorable HSE characteristics. Lafayette, Louisiana, USA: Society of Petroleum Engineers; 2008. doi:10.2118/112420-MS. Chakrabarty T. Solvent for extracting bitumen from oil sands. US Patent Application 20100 130 386; 2010. URL: http://www.freepatentsonline.com/20100130386.html. Reese RR, Rey P. Method of fracturing subterranean formations utilizing emulsions comprising acrylamide copolymers. US patent 7 482 310, assigned to Kroff Chemical Company, Inc. (Pittsburgh, PA) Superior Well Services, Inc. (Indiana, PA); 2009. URL: http://www.freepatentsonline.com/7482310.html. Poindexter MK, Marsh SC. Inorganic solid content governs water-in-crude oil emulsion stability predictions. Energy Fuels 2009;23(3):1258-68, doi:10.1021/ef800652n. Kirkpatrick WH, Alice W. Chemical compositions. US patent 2 925 429, assigned to Visco Products Company; 1960. URL: http://www.freepatentsonline.com/2925429. html. Leopold G. Breaking produced-fluid and process-stream emulsions. Washington, DC: American Chemical Society; 1992. p. 341-83. doi:10.1021/ba-1992-0231.ch010. Manning FS, Thompson RE. Dehydration of crude oil, vol. 2. 117 pp., Tulsa: PennWell Publishing; 1995. Kokal SL. Crude oil emulsions: a state-of-the-art review. SPE Prod Facil 2005;20(1):5-13, doi:10.2118/77497-PA. Poindexter MK, Lindemuth PM. Applied statistics: crude oil emulsions and demulsifiers. J Dispersion Sci Technol 2004;25(3):311-20, doi:10.1081/DIS-120037684. Poindexter MK, Chuai S, Marble RA, Marsh SC. The key to predicting emulsion stability: solid content. SPE Prod Oper 2006;21(3):357-64, doi:10.2118/93008-PA. Dalmazzone C, Seris H. Use of the DSC technique to characterize water in crude oil emulsions stability. Rev Inst Franc Petr 1998;53(4):436-71. Díaz-Ponce J, Flores E, Lopez-Ortega A, Hernández-Cortez J, Estrada A, Castro L, et al. Differential scanning calorimetry characterization of water-in-oil emulsions from Mexican crude oils. J Therm Anal Calorim 2010; 1-8. doi:10.1007/s10973-010-0904-8.

773

774

CHAPTER 21 Dispersions, emulsions, and foams

[105] Cravey RL. Citric acid based emulsifiers for oilfield applications exhibiting low fluorescence, US patent 7 691 960, assigned to Akzo Nobel N.V. (Arnhem, NL); 2010. URL: http://www.freepatentsonline.com/7691960.html. [106] Plateau JAF. Statique experimentale et theorique des liquides soumis aux seules forces moleculaires. Paris: Gauthiers-Villars; 1783. [107] Sebba F. Preparation of biliquid foam compositions. US patent 4 486 333; 1984. URL: http://www.freepatentsonline.com/4486333.html. [108] Sebba F. Foams and biliquid foams-Aphrons. Chichester: John Wiley & Sons; 1987. [109] Watcharasing S, Angkathunyakul P, Chavadej S. Diesel oil removal from water by froth flotation under low interfacial tension and colloidal gas aphron conditions. Sep Purif Technol 2008;62(1):118-27, doi:10.1016/j.seppur.2007.12.025. [110] Growcock FB, Simon GA. Stabilized colloidal and colloidal-like systems, US patent 7 037 881; 2006. URL: http://www.freepatentsonline.com/7037881.html. [111] Growcock FB, Belkin A, Fosdick M, Irving M, O’Connor B, Brookey T. Recent advances in aphron drilling-fluid technology. SPE Drilling Completion 2007;22(2):74-80, doi:10.2118/97982-PA. [112] Growcock F. Enhanced wellbore stabilization and reservoir productivity with aphron drilling fluid technology. Project Report DE-FC26-03NT42000, Houston, TX; 2005. [113] Belkin A, Irving M, O’Connor R, Fosdick M, Hoff T, et al. How aphron drilling fluids work. vol. 5. Richardsoon, TX: Society of Petroleum Engineers; 2005. p. 2380-6. doi: 10.2118/96145-MS. [114] Brookey T. Micro-bubbles: New aphron drill-in fluid technique reduces formation damage in horizontal wells. SPE. The Woodlands. Texas: Society of Petroleum Engineers; 1998. doi:10.2118/39589-MS. [115] Brookey TF. Aphron-containing well drilling and servicing fluids. US patent 6 716 797, assigned to Masi Technologies, L.L.C. (Houston, TX); 2004. URL: http://www. freepatentsonline.com/6716797.html. [116] Bjorndalen N, Kuru E. Physico-chemical characterization of aphron based drilling fluids. J Can Pet Technol 2008;47(11):15-21, doi:10.2118/08-11-15-CS. [117] API Standard RP 13B-1. Recommended practice for field testing water-based drilling fluids. API Standard API RP 13B-1, Washington, DC; 2009.