PEH Volume I Chapter 12: Crude Oil Emulsions

C1-3: Math
C4: Fluid Sampling
C5: Gas Properties
C6: Oil Correlations
C7: Thermo/Phase
C8: Phase Diagrams
C9: Asphaltene/Wax
C10: Produced Water
C11: Phase Behavior
C12: Emulsions
C13: Rock Properties
C14: Permeability
C15: Relative Permeability
C16: Economics
C17-18: Law

Emulsions are a common yet poorly-understood oilfield reality. Like hydrates, they seem to slip through the cracks and few want to claim them: do they belong to facilities, PVT, or production? I've just added yet another page to the Guidebook that deals with this complicated subject (7 PRD 13). The primary source? PEH chapter 12. See below:

Produced water: normally “free”; if an emulsion, typically:

water droplets dispersed (as internal phase, same surface area)…

…within oil or other (the external/continuous phase).

May be: “water in oil” (up to 80% water cut), or “oil in water” (>80% water cut), or more complex.

Emulsions: found everywhere; reservoir, wellbore, wellhead, facility, plant.

Created by: mixing (valves, pores, etc.) + emulsifier (stabilizing agent, such as fine solids & surfactants).

Surfactants: compounds partly soluble in oil and water.

Water-wet particles stabilize oil-in-water emulsions; Oil-wet particles stabilize water-in-oil emulsions.

Natural emulsions come from the “heavy” crude fraction.

Asphaltenes change wettability of solids so they act as emulsifiers.

Waxes crystalize if cooled below “cloud point” and create emulsions.

Tighter emulsions mean more, smaller droplets (more stable).

Sedimentation: settling water in an emulsion (due to oil/water density differences).

Creaming: raising oil droplets in the water phase (due to higher density of oil).

Emulsion treatment (demulsify) typically means removing water & associated salts.

Demulsification breaks emulsion to oil & water phases: 2 steps 1) flocculation, 2) coalescence.

Flocculation: aggregation/agglomeration/coagulation of component phases.

Coalescence: droplets irreversibly fuse (larger drops/lower surface area); high water cut enhanced.

Treatments: chemical (common), heating (common), electrostatic field (coalescence), settling.

Chemical demulsifiers: surface-acting compounds that neutralize emulsifying agent stabilizing effect.

Emulsion separation time: hours to days = “stable” or “tight”; minutes = “loose”.

Aromatic content in crude reduces emulsification.

Stability measured with a bottle test (estimates demulsifier phase separation time).

Mechanical emulsion-breaking: free water knockout drums/separators/desalters/settling tanks.

Emulsion prevention: reduce solids/chemicals/acids (make very tight emulsions)/mixing/turbulence.  

Macroemulsion & microemulsion differences because of formation and stability differences.

Macroemulsion: drop size >0.1 micrometer and will separate (thermodynamically unstable).

Most oilfield macro droplet coalescence can be reduced through a stabilization mechanism.

Microemulsion: drop size <10 nanometers, separate (thermodynamically stable).

Emulsion Separation Index Test (ESI): quantitative method for lab demulsifier testing (I-569).

…measure water amount separated at 5, 10, 15, 20 min; then 20 min centrifuged.

…bottle tests have a “qualitative” edge (due to sampling/operator/measurement error).

…uses dead crude (yet fresh emulsion samples to minimalize error).

Calculating ESI = [(Sum of Volume Separated with time)]/[(%BS&W)(# tests)]

Example: ESI = [0 + 4 + 12 + 19 + 25]/[(25)(5)] = 48% water separation