Demulsifier Dosing — Engineering Fundamentals
Emulsion chemistry, bottle-test interpretation, field-deployment scaling, sour-service compatibility, economics.
1. Why a demulsifier?
Crude-oil water emulsions are stabilized by interfacial films of asphaltenes, resins, naphthenic acids, fine solids, and (occasionally) production-chemical residues. The film prevents water droplets from coalescing and gravity-settling, so the emulsion stays dispersed and the crude leaves the treater with BS&W above pipeline spec (usually 0.5–1.0%).
A demulsifier is a tailored surfactant blend whose hydrophile-lipophile balance (HLB) is matched to the specific emulsion. It displaces the natural stabilizers from the interface, weakens the film, and lets droplets coalesce. Dose is small (5–100 ppm typical) because the chemical works at the interface — it's catalytic, not stoichiometric.
2. Demulsifier chemistry families
| Family | HLB | Best for |
|---|---|---|
| Polyalkylene glycols | 2–6 | Light-to-medium crude, loose emulsions |
| Oxyalkylated phenol-formaldehyde resins | 4–10 | Medium-to-tight emulsions, heavy crude |
| Polyamines / polyamides | 6–12 | Sour crude (sulfur-tolerant) |
| Quaternary ammonium | varies | Reverse emulsions (oil-in-water) |
| Silicone-modified | varies | Foam-prone crude (also defoamer effect) |
Vendors blend multiple chemistries to hit a specific HLB and asphaltene-displacement profile. Commercial products are typically 20–60% active diluted in aromatic naphtha or 2-ethylhexanol carrier.
3. Bottle-test selection
The classic field selection method:
- Pull a representative wellhead or treater-inlet sample (~1 L).
- Distribute into clear 100-mL graduated bottles.
- Dose each bottle with a candidate demulsifier at 25, 50, 75, 100, 150 ppm.
- Heat the bottles to expected treating T (60–80 °C / 140–180 °F).
- Read water break-out volume at 5, 15, 30, 60 minutes.
- Select the chemistry + lowest dose that gives clean oil + clear water by 30 min.
Bottle test gives the optimal dose at bottle conditions. Field dose almost always differs because field T, mixing energy, and bulk emulsion age differ.
4. Bottle → field scaling
The calculator applies three independent corrections:
Lower field T → more chemical (emulsion is more stable). Higher field T → less. Square-root form approximates the Arrhenius temperature dependence of interfacial film viscosity.
High water cut means more interface to treat. Below 30% the correction is negligible; above 30% chemistry demand grows roughly linearly.
Asphaltenes are the principal natural stabilizer. Each percent asphaltene above ~2% adds 2% to the chemistry demand.
Sour streams degrade some demulsifier chemistries and need sulfur-tolerant blends (polyamines, oxazolines), typically at +10–50% dose vs. sweet baseline.
5. Dose-rate math
ppm-by-volume in oil → gal/day of formulated product:
Where strength_frac is the active-ingredient fraction (e.g., 0.40 for a 40%-active product). Mass and active-basis figures follow from product density (typical 6.5–9.5 lb/gal).
Pump sizing: a standard chemical metering pump is sized at 1.25× of required gph to provide turndown for swings in crude rate or chemistry demand. Typical pumps in this duty range from 0.5 to 50 gph electrically-driven diaphragm.
6. Economics
Demulsifier cost runs $0.02 – $0.10 per bbl of crude treated. At the high end, chemistry cost can rival the OPEX of the heater treater itself, so vendor-evaluation tournaments are common: compare 3–5 products at the same bottle-test conditions, then trial the top 2 in the field for a week each and pick the lower $/bbl that meets BS&W spec.
Heating + chemistry is a trade-off:
- Raise treating T by 20 °F → demulsifier demand drops ~5–10% (T correction).
- But each 20 °F of additional ΔT costs fuel gas — typically more than the chemistry savings unless gas is essentially free.
For sour crude in remote locations where chemistry logistics are expensive, the optimum tilts toward higher T + less chemical. For pad operations with cheap chemistry trucks and an electric heater, lower T + more chemical can win.
7. References
- GPSA Engineering Data Book §19 — Crude Oil Treating.
- Manning, F.S. & Thompson, R.E. (1995). Oilfield Processing of Petroleum Vol. 2, Ch. 4 — Emulsion Treating.
- Schramm, L.L. (1992). Emulsions: Fundamentals and Applications in the Petroleum Industry. Adv. Chem. Series 231.
- Stewart, M. & Arnold, K. (2008). Surface Production Operations Vol. 1, 3rd ed., Ch. 7.
- NACE TM0212 — Detection, Testing, and Evaluation of Microbiologically Influenced Corrosion (chemistry compatibility).
- Vendor literature: Champion X, Baker Hughes, Nouryon (Akzo), Croda, Innospec.