The formation of emulsions during oil production is a costly problem, both in terms of chemicals used and production lost. This paper discusses production and operational problems related to crude-oil emulsions and presents a review that will be useful for practicing engineers.The first part of this paper presents why emulsions form during oil production, the types of emulsions encountered, and new methods for characterizing them. Crude-oil emulsions are stabilized by rigid interfacial films that form a "skin" on water droplets and prevent the droplets from coalescing. The stability of these interfacial films, and hence, the stability of the emulsions, depends on a number of factors, including the heavy material in the crude oil (e.g., asphaltenes, resins, and waxes), solids (e.g., clays, scales, and corrosion products), temperature, droplet size and droplet-size distribution, pH, and oil and brine composition. The effects of these factors on emulsion stability are reviewed within this paper.The second part of this paper presents methods to tackle crudeoil emulsions. The focus is on the destabilization of emulsions and the demulsification process. Emulsions are destabilized by increasing temperature and residence time, removal of solids, and controlling emulsifiers. The mechanisms involved in demulsification (e.g., flocculation, aggregation, sedimentation, creaming, and coalescence) are discussed in terms of the stability of the interfacial films. The methods involved in demulsification-including thermal, mechanical, electrical, and chemical-are also presented. Experience and economics determine which methods are used, and to what degree, for emulsion treatment.Finally, a section on field applications also is included that should be useful for the practicing engineer who deals with emulsions either regularly or on a limited basis. Herein the fieldemulsion treatment program is discussed, and more importantly, methods to prevent emulsion problems are highlighted. Recommendations are made for reducing and optimizing demulsifier dosage and controlling emulsion problems.

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The nature of asphaltenes and their role in the production and processing of crude oils has been the topic of numerous studies. This is due to the fact that the economics of oil production can be seriously affected by the asphaltene deposition problem. This paper presents a novel method to visualize in situ asphaltene precipitation from heavy oils with light hydrocarbon gases, e.g. methane. propane, ethane/propane mixtures, and carbon dioxide at reservoir pressures and temperatures. Experimental results are reported for the effects of temperature (up to 100 °C), pressure (up to 20 MPa) and composition on the formation of asphaltene precipitates from heavy crude oils. A series of titration experiments were conducted with several n-alkanes to determine the amount of asphaltenes precipitated. Both the amount and nature of the precipitate varied with the solvent used. Propane was the most prolific of all the solvents used in precipitating asphaltenes from the heavy oils. A thermodynamic model proposed by Hirshberg et al. was used to correlate the experimental data. Introduction Miscible and immiscible flooding of crude oil reservoirs by light hydrocarbon gases, carbon dioxide and other injection gases has become a popular method for enhanced oil recovery(1). The flooding process, however, causes a number of changes in the flow and phase behaviour of the reservoir fluids and can significantly alter rock properties. Such changes include the precipitation of asphaltenes(2) and wettability reversal which can alter recovery efficiencies. The existence of asphaltenes in crude oils and their deposition inside reservoirs and wellbores can cause severe problems and affect the efficiency and cost of petroleum production. The important parameters that affect asphaltene precipitation during gas injection are the compositions of the crude oil and the solvent gas, and the pressure and temperature of the reservoir(3–5). Precipitation of asphaltenes is a complex process and it is generally followed by flocculation which produces an insoluble material in the heavy oi1(6). Asphaltenes are believed to be stabilized in solution by resins and aromatics and the asphaltene/resin ratio plays a key role in their precipitation. This ratio is more important than the absolute asphaltene content in determining which crudes will be subject to precipitation. Problems arising from asphaltene deposition have been reported in the literarure(7,8) for many field projects. Some examples of these are the Ventura field in California(9), Hassi Messaoud field in Algeria(l0) and heavy oil fields in Venezuela(l1). Deposition of asphaltenes in the wellbore can be a serious production problem and may require frequent solvent washings and scrapings to maintain oil production(10). Significant damage can be caused during well acidizing because the acid can cause the asphaltenes to precipitate and form rigid films. Other problems associated with asphaltene precipitation are the seizure of downhole safety valves submersible pumps, hinderance in wireline operations and production restrictions. These problems are discussed in derail by Leontaritist(7). Presently asphaltenes are removed either by mechanical cleaning, chemical cleaning, or by manipulating reservoir conditions (for example, pressure, production rates, etc,)(10,12). The approach taken by the oil industry has been a remedial one.

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The emulsion stabilizing properties of a low-total-acid-number (TAN) crude oil, which had initially been attributed to asphaltenes and calcite precipitation, were re-analyzed with regard to the role of organic acids. Despite high asphaltenes content, this crude oil exhibits features classically observed with acidic oils, such as the increase in emulsion stability upon pressure decrease/pH increase or the poor efficiency of demulsifiers. The potential for a significant role of organic acids was confirmed by the high interfacial activity of indigenous acids, as extracted from the crude oil by means of an ion-exchange resin. This was further addressed analyzing the molecular chemistry of the interfacial layer and its rheology. The interfacial material was found to be composed of a mixture of asphaltenes and organic acids. These acids exhibit a wide range of structures (mono- versus dicarboxylic, fatty versus naphthenic and benzoic) and molecular weights (from 200 to 700 g/mol), contrary to the medium molecular weight fatty monocarboxylic acids that are generally believed to cause “soap emulsions”. The interfacial rheology is indicative of a 2D gel, with an assumed glass transition temperature of approximately 40 °C. In conclusion, this study shows that a co-precipitation of asphaltenes and organic acids can promote the build up of a very cohesive interface. The disruption of this interface not only requires the drainage of individual molecules but also a collective yield of the gel. This paper is part one of two: it confronts physical and chemical data, the latter being further detailed in an associated paper.

Formation of emulsions during oil production is a costly problem, both in terms of chemicals used and due to production losses. This paper discusses production and operational problems related to crude oil emulsions, and present a review that will be very useful for practicing engineers. The first part of this paper presents why emulsions form during oil production, the types of emulsions encountered, and new methods for characterizing them. Crude oil emulsions are stabilized by rigid interfacial films that form a "skin" on water droplets and prevent the droplets from coalescing. The stability of these interfacial films, and hence the stability of the emulsions, depends on a number of factors including the heavy polar material in the crude oil (asphaltenes, resins, waxes, etc), solids (clays, scales, corrosion products, etc), temperature, drop size and drop size distribution, pH, oil and brine composition. These effects on emulsion stability are reviewed. The second part of this paper presents ways to tackle crude oil emulsions. The focus is on the destabilization of emulsions and the demulsification process. Emulsions are destabilized by increasing temperature and residence time, removal of solids, and controlling emulsifiers. The mechanisms involved in demulsification (flocculation, aggregation, sedimentation, creaming, and coalescence) are discussed in terms of the stability of the interfacial films. The methods involved in demulsification including thermal, mechanical, electrical, and chemical are also presented. Experience and economics determine which methods and to what degree each method is used for emulsion treatment. Finally, a section on field applications is included that should be useful for the practicing engineer who deals with emulsions, either regularly or on a limited basis. Herein the field emulsion treatment program is discussed, and more importantly, methods to prevent emulsion problems are highlighted. Recommendations are made for reducing and optimizing demulsifier dosage and controlling emulsion problems. Introduction Crude oil is seldom produced alone. It is generally commingled with water which creates a number of problems during oil production. Produced water occurs in two ways: some of the water may be produced as free water, i.e. water that will settle out fairly rapidly, and some of the water may be produced in the form of emulsions. Emulsions are difficult to treat and cause a number of operational problems such as tripping of separation equipment in gas-oil separating plants, production of off-spec crude oil, and creating high pressure drops in flow lines. Emulsions have to be treated to remove the dispersed water and associated inorganic salts in order to meet crude specification for transportation, storage and export and to reduce corrosion and catalyst poisoning in downstream processing facilities. Emulsions can be encountered in almost all phases of oil production and processing: inside the reservoirs, well bores and well heads, wet crude handling facilities, transportation through pipelines, crude storage and during petroleum processing. This paper provides a review of crude oil emulsions. However, the review is limited to the produced oilfield emulsions at the well head and at the wet crude handling facilities. It looks at the characteristics, occurrence, formation, stability, handling and breaking of produced oilfield emulsions. A crude oil emulsion is a dispersion of water droplets in oil. Produced oil-field emulsions can be classified into three broad groups:Water-in-oil (W/O)Oil-in-water (O/W)Multiple or complex emulsions

#Presently with Saudi Aramco, Dhahran, SAUDI ARABIA Abstract Asphaltene precipitation and deposition has been recognized to be a significant problem in oil production, transmission, and processing facilities. The precipitation of asphaltenes is caused by a number of factors including changes in pressure, temperature, chemical composition of the crude oil, mixing the oil with diluents or other oils, and during acid stimulation. The precipitated asphaltenes reduces the permeability of the reservoir near the wellbore region causing formation damage and can plug-up the well-bores and well tubings. Deposition of asphaltenic organic scales leads to operational problems, safety hazards and an overall decrease in production efficiency, thereby increasing the cost of oil production. This paper presents a review of the important factors which affect asphaltene precipitation in petroleum reservoirs and in processing facilities. The nature and characteristics of asphaltenes in the crude oil and their molecular and colloidal properties are discussed. A description of the asphaltene deposition problem manifestations in the reservoir, well bores and well tubings, processing and transportation equipment is presented. Current research work in this area is also discussed. Introduction Miscible and immiscible flooding of crude oil reservoirs by light hydrocarbon gases, carbon dioxide and other injection gases has the potential for enhanced recovery. The flooding process however causes a number of changes in the flow and phase behavior of the reservoir fluids and can significantly alter rock properties. One such change is the precipitation of asphaltenes which can adversely affect the productivity of the reservoir during the course of oil recovery. Precipitation of asphaltenes can cause formation plugging and wettability reversal which can lead to reduced recovery efficiencies. In many cases, the precipitated asphaltenes can plug up the well tubing or can be carried to the well head and downstream separators causing expensive problems. Presently the asphaltenes are removed either by mechanical cleaning, chemical cleaning or reservoir condition manipulation. P. 169

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