Refineries live by numbers: ≤0.2 vol% BS&W and ≈10 lb salt per 1,000 bbl. The margin comes from demulsifiers — and from where, when, and how they’re injected.
Pipeline-bound crude generally has to meet tight specifications — think ≤0.2 vol% BS&W (basic sediment and water) and ≈10 lb salt per 1,000 bbl (often expressed as PTB, pounds per thousand barrels) — according to SPE/PetroWiki. Residual entrained water carries dissolved chlorides that drive corrosion and fouling downstream. Dilution water and electrostatic coalescence (an electric‑field separator) do much of the heavy lifting, but chemical emulsion breakers — demulsifiers — are often essential, especially with heavy or stabilizing crude blends.
Modern demulsifiers are surfactant/polymer formulations in hydrocarbon solvents that destabilize the interfacial film around water droplets so they coalesce and settle. One Algerian study reports a high‑dose wash — 5% DBS demulsifier plus 5% wash water at 52 °C — achieving 96.9% salt‑removal efficiency and 0.5% BS&W with no electric field applied (ResearchGate). In practice, typical demulsifier dosages are much lower (sub‑100 ppm) and are optimized to meet spec at minimal cost (SPE; Digital Refining).
Commercial programs typically source the blends alongside other oilfield treatments; many suppliers package demulsifiers within broader oilfield chemical lines.
Demulsifier chemistry and HLB selection
Commercial demulsifiers (emulsion breakers) are complex blends of: (1) solvents (for example, toluene, xylene, short alcohols) that carry actives and weaken asphaltenic films; (2) surfactants chosen by HLB (hydrophile–lipophile balance, a measure of how water‑ or oil‑loving a molecule is) to displace native emulsifiers (SPE); and (3) flocculants (polymers or salts) that charge‑balance droplets and aggregate them (SPE).
Because indigenous film materials in crude — asphaltenes, resins, and fine solids — typically show HLB ≈3–8, formulators favor higher‑HLB, more hydrophilic surfactants to out‑compete the native interfacial film (SPE). Packages can be ionic (anionic or cationic; often polyoxyalkylated alkylphenols/alcohols) or nonionic (polyethylene/polypropylene oxide copolymers, ethoxylated alcohols) depending on feed chemistry.
Polymeric demulsifiers have gained attention: alkylene oxide diesters, ethylcellulose‑based products, and polyether copolymers. One polyester‑block demulsifier achieved 97.5% water removal in 45 minutes in lab work (MDPI/Processes). Advanced variants — magnetic nanoparticles and Janus submicron particles — can reach 95–99% separation efficiency in studies (MDPI/Processes). Still, practical plants primarily use solvent–surfactant blends tailored to their crude.
Bottle test selection protocols
Bottle tests — mixing field emulsion (oil plus entrained water) with candidate demulsifiers in graduated centrifuge tubes and recording water dropout/rag over time — are the industry standard for screening (SPE; OGST 2021). “Rag layer” refers to the stubborn interfacial emulsion band that can persist between oil and water phases.
Best practice matters. Fresh sampling is critical — minutes‑old emulsions — because aging thickens emulsions and raises apparent dosage needs (SPE). Tests should run at representative temperature (often slightly below refinery feed temperature) and water‑cut; because volatility loss alters viscosity, closed tubes are standard (OGST 2021).
Screen several chemicals and dosages. Typical comparisons span 10–50 ppm (0.001–0.005 vol%) and, if needed, up to 200 ppm (SPE). Suites should reflect field variability — different water cuts and seasonally varying temperatures (SPE). Record not just water‑out volume but clarity and any rag/solids; cloudy water or persistent rag signals poor performance, even with high dropout (SPE).
Results are often plotted as water‑out versus time. In one Saudi facility, Raynel et al. (2021) showed a bottle that yielded 10% vol water at 50 ppm after 60 minutes matched a plant draw‑off of ≈9–11% under similar conditions (OGST 2021). By contrast, a poorly mixed demulsifier B gave only 5% in the bottle but 16% in the plant — a case where static bottle tests under‑estimated performance due to mixing effects (OGST 2021). Typically, lab bottle tests over‑predict the required dosage; the field often needs less chemical (OGST 2021; SPE).
The goal is to identify one or two promising candidates that deliver the fastest, cleanest split, then confirm them in‑plant (SPE). Quantitative enhancements include precisely measuring demulsifier mass and adjusting for residence time (OGST 2021). Surveys emphasize consistent methods and “live” emulsion protocols (including freeze‑dried handling notes) to improve reproducibility (OGST 2021).
Injection point and mixing energy
Proper injection location and mixing intensity determine whether demulsifier contacts every droplet and its interfacial film. A “certain amount of shear” is required to disperse the chemical, per SPE/PetroWiki. In practice, demulsifier is typically injected upstream of the electrostatic coalescer into the crude/water stream.
Upstream/in‑line injection uses quills or tees feeding high‑flow locations — often just ahead of a mixing valve or static mixer — so the chemical entrains in the oil stream (SPE; SPE). Inline mixers (kinetic static mixers, eductor pumps) help force full dispersion; “adequate mixing of the chemical in the emulsion” is essential (SPE). Continuous dilute injection — not slugging — improves uniformity; diluting the product increases injected volume and distribution (SPE). Accurate, low‑rate feed is typically handled with dosing pumps.
Existing shear (turbulence through valves, elbows, manifolds) usually suffices to disperse the chemical, but low‑flow conditions can warrant added devices. Common solutions include static (motionless) mixers such as Kenics elements and mixing valves designed for ~5–20 psi differential, as well as kinetic/vortex mixers (PetroWiki; PetroWiki; SPE). Adding Kenics elements downstream of the mix valve can improve blending while minimizing destructive shear (PetroWiki).
Mixing energy should be moderate. High shear — violent churn, sharp pressure drops — creates tiny droplets that resist coalescence (SPE; SPE). The target is turbulence just strong enough to spread the chemical: normal flow through pipes, valves, or a static mixer provides low‑to‑moderate energy that mixes the demulsifier without further shrinking droplet size (SPE; SPE).
Injection is typically set as far upstream as practical — often at the mix‑valve inlet or just after the crude preheater (SPE). Farther upstream increases residence time for the chemistry, although too far can allow premature settling or raise corrosion risks in piping. Large units often use multiple injection points. One Southeast Asian refinery split 5–10 ppm demulsifier into two feeds — a quill ahead of the crude heater and one at each stage’s mix valve — for thorough distribution; the desalted crude measured <0.5 PTB salt and 0.2% BS&W (free water) (Digital Refining; Digital Refining).
Field results and optimization ranges
The right chemistry and injection strategy deliver measurable gains. In the two‑stage case above, the unit hit <0.5 PTB salt and 0.2% BS&W with only 8% wash water (Digital Refining). Literature frequently reports >90% water removal in minutes under optimized lab conditions. Martínez‑Palou et al. achieved ≈89.5% water removal using an ionic surfactant at 900 mg/L (~900 ppm) (MDPI/Processes), and other work found ~95–97% removal with a high‑MW nonionic demulsifier or polymer (MDPI/Processes; MDPI/Processes). (These high‑dose lab figures underline that the right chemistry can, in principle, almost fully break emulsions.)
In the field, refineries aim for the minimal dose that meets spec. Typical operating ranges are 10–50 ppm (≈1–4 gal/1,000 bbl) (SPE). Continuous fall‑back trials show that overdosing above the optimal ppm can worsen emulsions, building rag layers and raising residual water (SPE). Plants therefore run periodic dosage curves or use automated controllers to hold chemical inventory to the necessary minimum (SPE; SPE).
Systematic re‑evaluation — bottle test screening followed by field trials — can cut demulsifier consumption by 30–50% while maintaining product quality, according to one survey (ResearchGate). Performance metrics remain concrete: BS&W%, salt mg/L, and vol% free water. Across the studies cited, a careful mix of lab testing and engineered injection produces predictable, data‑backed gains in desalter efficiency (OGST 2021; Digital Refining).
Sources and reference datasets
Authoritative references include industry handbooks (SPE/Petrowiki) and case studies (SPE; SPE), peer‑reviewed journals (Oil & Gas Sci. Technol. 2021, OGST 2021; Processes 2019, MDPI/Processes), US refinery data (Digital Refining), and regional plant studies (ResearchGate; ResearchGate).
