Emulsion

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Different types of oilfield emulsions.

In oilfield, emulsion most commonly refers to water droplets in a continuous oil phase, which is also called water-in-oil (W/O) emulsions. Other types of emulsions include oil-in-water (O/W) emulsions (oil droplets in a continuous water phase, sometimes referred to as “reverse” emulsions), and multiple emulsions (e.g. water droplets suspended in larger oil droplets that in turn are suspended in a continuous water phase). Emulsion formation can potentially drastically increase the bulk fluid viscosity, depending on oil/water ratio and the types of emulsion.

Since oil is typically co-produced with water, emulsions can be encountered in almost all phases of oil production and processing: inside the reservoirs, wellbores, wellheads, and wet crude-handling facilities; transportation through pipelines and crude storage; and during petroleum processing. The formation of emulsions during oil production is a costly problem, both in terms of chemicals used for processing to meet product quality and lost production due to emulsion incurred processing system shut-down or increased pressure drop due to increased viscosity.

Contents

Emulsion formation during hydrocarbon production

Emulsion formation typically requires mixing between two phases and emulsion stabilizing agents.

Mixing

The production and processing of oil and water offer several possibilities to vigorously mix the phases and create an emulsion. Emulsification process can start already in the reservoir where the crude oil and water is squeezed through narrow pores. When the crude oil flows from the reservoir into the the production tubing, and from the wellhead to the manifold, there is usually a substantial pressure reduction with a pressure gradient, especially over chokes and valves where the mixing of oil and water can be intense. After this, the production fluid enters the separators (usually several placed sequentially in a train), where most of the water is separated from the crude. The final treatment normally takes place in the electro-coalescer after which the level of water should be below 0.5%.

Some fields have pumps as artificial lift methods, which further create opportunities for intense mixing and increase emulsion risk.

Stabilizing agents

Emulsions are stabilized by emulsifiers (i.e., surface-active agents, or surfactants) that tend to concentrate at the oil/water interface where they form interfacial films. This generally leads to a reduction of interfacial tension (IFT) and promotes dispersion and emulsification of the droplets[1].

  • Naturally occurring emulsifiers in the crude oil include higher boiling-point fractions, such as asphaltenes and resins, and organic acids and bases. These compounds are believed to be the main constituents of interfacial films, which form around water droplets in an oilfield emulsion.
  • Other surfactants that may be present are from chemicals that are injected into the system (e.g., drilling fluids; stimulation chemicals; and injected inhibitors for corrosion, scale, waxes, and asphaltenes control).

Fine solids can also act as mechanical stabilizers. These particles, which have to be much smaller than emulsion droplets, collect at the oil/water interface and are wetted by both the oil and water. The effectiveness of these solids in stabilizing emulsions depends on a number of factors, such as particle size, particle interactions, and the wettability of the particles. Finely divided solids found in oil production include clay particles, sand, asphaltenes and waxes, corrosion products, mineral scales (especially iron sulfide (FeS), and drilling mud.

Viscosity of emulsions

Viscosity of emulsions can be substantially higher than the viscosity of either the oil or the water. This is because emulsions show non-Newtonian behavior[2] caused by droplet “crowding” or structural viscosity. At certain volume fractions of the water phase (water cut), oilfield emulsions behave as shear-thinning, or pseudo-plastic, fluids, that is, as shear rate increases,their viscosity decreases.

The viscosity of emulsions depends on a number of factors:

  • Viscosities of oil and water.
  • Volume fraction of water dispersed.
  • Droplet-size distribution.
  • Temperature.
  • Shear rate.
  • Amount of solids present.

Factors that impact emulsion stability

Heavy fraction

It is now well recognized that the naturally occurring emulsifiers (or stabilizers) are concentrated in the higher-boiling-point, polar fraction of the crude oil[3][4][5]. These include asphaltenes, resins, and oil-soluble organic acids (e.g., naphthenic and carboxylic acids) and bases. These compounds are the main constituents of the interfacial films surrounding the water droplets that give the emulsions their stability.

While asphaltenes will stabilize emulsions when they are present in a colloidal state (not yet flocculated), there is strong evidence that their emulsion-stabilizing properties are significantly enhanced when they are precipitated from the crude oil and are present in the solid phase.

Solids

Fine-solid particles present in the crude oil are capable of effectively stabilizing emulsions, such as asphaltenes, scales, corrosion products, etc. Solid particles stabilize emulsions by diffusing to the oil/water interface where they form rigid structures (films) that can sterically inhibit the coalescence of emulsion droplets. Furthermore, solid particles at the interface may be charged, which may also enhance the stability of the emulsion. The wettability of solid particles plays an important role in the emulsion-stabilizing process. It must be wetted by both the oil and water phases for it to act as an emulsion stabilizer.

Examples of oil-wet solids are asphaltenes and waxes. Examples of water-wet solids are inorganic scales (e.g., CaCO3 and CaSO4), clays, and sand. Water-wet particles can be made oil-wet with a coating of heavy-organic-polar compounds[6].

Temperature

Higher temperature decrease emulsion stability by affecting the physical properties of oil, water, interfacial films, and surfactant solubilities in the oil and water phases.

Droplet size

The smaller the droplet size, the stabler the emulsion is.

Brine pH and composition

Emulsion stability as a function of pH and brine composition.

The pH of the water affects the rigidity of the interfacial film by influencing the ionization of the interfical film constitutents (organic acids and bases, asphaltenes with ionizable groups, and solids) and radically changes the physical properties of the films.

Frequently, severe emulsion upsets occur in surface treating facilities, following acid stimulation[7][8].

Brine composition also has an important effect (in relation to pH) on emulsion stability as a result of ionization effect (i.e., association/interaction of ions present in the brine with the asphaltenes).

Emulsion breaking methods

In the oil industry, crude-oil emulsions must be separated almost completely before the oil can be transported and processed further. Emulsion separation into oil and water necessarily involves the destabilization of emulsifying films around water droplets. This process is accomplished by any one or a combination of the following methods[9]:

  • Reducing the flow velocity that allows gravitational separation of oil, water, and gas. This is generally accomplished in large volume separators and desalters.
  • Adding chemical demulsifiers.
  • Increasing the temperature of the emulsion.
  • Applying electrical fields that promote coalescence.
  • Changing the physical characteristics of the emulsion.

The most common methods of emulsion treatment have been the application of heat and appropriate chemical demulsifiers to promote destabilization, followed by a settling time to allow gravitational separation to occur.

Emulsion treating guidelines

  • Each producing stream is unique and must be evaluated individually to determine the best separation strategy. Laboratory tests with actual samples are recommended; however, data from nearby wells and/or fields can be used as estimates.
  • The planning for future emulsion treatment should begin during the early design of the separation facility. For example, if watercuts are anticipated to increase, appropriate measures should be taken in the design phase for increased water handling.
  • Operational experience and laboratory work are necessary to substantiate emulsion concerns and identify solutions. Pilot and plant tests should determine the actual treatment requirements. Bottle tests have limitations in determining dosage, but are good for screening and trend analysis.
  • Treatment capacities can be increased for existing separator trainsby re-engineering and retrofitting. For example, internal packing can be installed in the separator for improving emulsion resolution.
  • For existing systems, record demulsifier and other relevant operational data (e.g., production rates, water cuts, temperatures, and costs) over a period of time. These data can be useful for analyzing demulsifier dosages (e.g., during the summer and winter) and unit-demulsifier costs, and can pinpoint certain activities that may be responsible for emulsion upsets and underlying problems. These data are also very useful for optimizing emulsion treatment programs.
  • Review the emulsion-treatment program periodically as conditions change. The frequency of evaluation depends on many factors, including the relative cost of the demulsifier usage, heating costs, capacity limitations, and manpower requirements.

Recommendations

The most effective treatment is to find ways to avoid the problem in the first place. The following are recommended to minimize emulsion risks:

  • Control generation of solids, such as asphaltenes, scales, and corrosion products.
  • To design an acid job, incorporate effective demulsifiers at high concentrations, use mutual solvents, avoid commingling, and minimize fines and precipitates during acidization.
  • The effect of amount, rate, and salinity of wash water on desalter performance should be investigated.
  • Effect of aromatic solvents used as carriers on demulsifier activity should be investigated.
  • Minimize mixing intensity when possible.
  • Operational data should be maintained for each facility. Optimization of emulsion-treatment programs should be an ongoing activity.

References

  1. Tambe, D.E. and Sharma, M.M.: “Factors Controlling the Stability of Colloid-Stabilized Emulsions,” J. of Colloids and Interface Science (1993) No. 157, 244–253.
  2. Emulsions: Fundamentals and Applications in the Petroleum Industry, L.L. Schramm (ed.), Advanced Chemical Service Monograph Series, American Chemistry Soc., Washington DC (1992) 231.
  3. Jones, T.J., Neustadter, E.L., and Wittingham, K.P.: “Water-in-Crudeoil Emulsion Stability and Emulsion Destabilization by Chemical Demulsifiers,” J. Cdn. Pet. Tech. (April–June 1978) 100–108.
  4. Strassner, J.E.: “Effect of pH on Interfacial Films and Stability of Crude Oil/water Emulsions,” JPT (March 1968) 303–312.
  5. Bobra, M.: “A Study of the Formation of Water-in-Oil Emulsions,”Proc., 1990 Arctic and Marine Oil Spill Program Technology Seminar, Edmonton, Canada (1990).
  6. Kokal, S.L. and Al-Juraid, J.I.: “Reducing Emulsion Problems By Controlling Asphaltene Solubility and Precipitation,” paper SPE 48995 prepared for presentation at the 1998 SPE Annual Technical Conference and Exhibition, New Orleans, 27–30 September.
  7. Coppel, C.P.: “Factors Causing Emulsion Upsets in Surface Facilities Following Acid Stimulation,” JPT (1975) 1060–1066.
  8. Ali, S.A., Durham, D.K., and Elphingstone, E.A.: “Test Identifies Acidizing Fluid/Crude Compatibility Problems,” Oil & Gas J. (March1994) 47–51.
  9. Kokal, S.L.: “Crude-Oil Emulsions,” Petroleum Engineering Handbook,SPE, Richardson, Texas (2005).