Magnesium chloride that slips past the crude desalter can turn into hydrochloric acid at ~500 °F — and eat steel fast. Refineries are pushing pH control, film-forming inhibitors, and corrosion‑resistant alloys to stop pitting, leaks, and shutdowns.
Crude oil arrives with dissolved salts (NaCl, CaCl₂, MgCl₂) and organic acids. In a single-stage unit, removal is uneven: about ~90% of NaCl can be stripped, but only ~40% of MgCl₂, meaning ~60% of MgCl₂ still passes through (ogj.com). That’s a problem because MgCl₂ can hydrolyze at ~500 °F, generating HCl (hydrochloric acid) that accelerates metal loss (ogj.com).
Corrosion doesn’t hit evenly. Pitting often concentrates in the bottom third of the desalter shell where brine collects (integratedglobal.com). If uncontrolled, the attack escalates into stress corrosion cracking (SCC) in the liquid phase and unplanned shutdowns. Industry estimates peg refinery corrosion costs in the hundreds of millions annually. The fix starts with chemistry, then metallurgy.
Baca juga:
Chemical injection and film formation
Refiners dose two categories of chemicals: neutralizers and film-forming inhibitors. Neutralizers include ammonia and caustic (NaOH) that react with HCl and lift water-phase pH. In field cases, ammonia injection raised condensed water pH from ~1.5 to ~5.5–6.5, sharply cutting corrosion (researchgate.net). Caustic dosing is deliberately limited — typical targets are 5–10 ppm (parts per million) NaOH‑equivalent in the crude, about 0.3–0.7 kg NaOH per 1,000 bbl (barrels) — with brief 10–20 ppm shots during startup or upset; over‑dosing risks SCC (researchgate.net) (researchgate.net).
Film-forming inhibitors — often aminic organics that adsorb to steel — build a protective barrier. These include alkylene polyamines (such as ethylenediamine) and imidazoline derivatives (digitalrefining.com). Suppliers and operators commonly split injection between the crude tank and the desalter vessel; some apply half the dose to the charge tank and half directly into the desalter juice (ogj.com). Typical rates run a few ppm; one study found ~6 ppm of a demulsifier/inhibitor blend was optimal, with recommended limits “a few ppm to about 100 ppm,” and many units running ~5–15 ppm in steady state and higher during start-up (researchgate.net) (researchgate.net).
Results are measurable. Refiners in the Riyadh area reported that continuous film aminic inhibitors plus caustic control to hold brine pH ~6 cut preheat train corrosion roughly an order of magnitude — from >0.5 mm/yr to <0.05 mm/yr — depending on crude acid content (researchgate.net) (researchgate.net). Compared with the cost of a single leak or a lost turnaround day, equipment for inhibitor injection runs to tens of dollars per ppm‑ton. For programs like these, refiners often source blended oilfield chemicals and pair them with precise dosing pumps to maintain target rates, while film protection relies on targeted corrosion inhibitors and, where emulsions demand it, a tuned demulsifier package.
pH management in wash water
pH (a measure of acidity/alkalinity) drives HCl availability. Maintaining mildly alkaline desalter wash/brine pH is essential; industry practice holds the wash in the ~6.5–7.5 range (ogj.com). One guideline states: “Control desalter pH to 6.5–7.5 and do not add caustic to sour‑water stripper bottoms” — instead, use ammonia (ogj.com). Overhead condensed water should stay above about pH 5 via neutralizers (NH₃ or organic bases) (researchgate.net).
In practice, injection of ~0.5–1.0 kg NH₃ per 1,000 bbl of crude is used to hold overhead pH ≈6, essentially eliminating acid dewpoint corrosion (researchgate.net). Conversely, if pH falls below ~4–5, corrosion accelerates; one report saw overhead pH ≈1.5 during interrupted control, with NH₃ injection to pH≈6 quickly suppressing the attack (researchgate.net) (researchgate.net). Very high pH (>9) causes its own problems (iron precipitation, emulsion inversion). Many operators now monitor pH online — Memosens pH probes in brine loops — and adjust neutralizer feed in closed loop to keep brine ~6–7. Refineries often specify a neutralizing amine for trim control, delivered via automated dosing pumps to track sensor feedback.
Baca juga:
Kondensat Sterilizer Sawit: Limbah Panas yang Bisa Diubah Jadi CPO dan Penghematan Energi
Corrosion‑resistant alloys and claddings
Even with chemistry dialed in, “blind” localized attack persists. Carbon steel is rarely used in the liquid phase of modern desalters. Many internals (electrodes, grids, support plates, piping) are upgraded to corrosion‑resistant alloys (CRAs): 316L or 317L stainless (≥2.5% Mo) for weld‑pads and brass electrodes, and 90‑10 copper‑nickel or super‑austenitic/ferritic grades for brine discharge piping. In severe cases (high chlorides/naphthenic acids), refineries deploy high‑nickel Alloy 59 cladding or Monel 400 components.
Some sites “re‑spray” the bottom third of in‑service shells with a dense CRA coating. One provider applies a high‑velocity thermal spray (HVTS) to lay down a thick nickel‑based alloy, forming an “impermeable inert barrier” that halts brine etching (integratedglobal.com), a practice reported to “extend asset availability and reduce downtime and OPEX” (integratedglobal.com). In one comparison, switching from carbon steel to 316L for a small geometry part in the acid zone cut corrosion from ~0.3 mm/yr to <0.02 mm/yr — over 90% reduction — with extra material cost roughly 3–10× steel often offset by tripled service life.
Baca juga:
Mengapa Sterilizer Horizontal & Kontrol Otomatis PLC/SCADA Jadi Pilihan Utama di Pabrik Kelapa Sawit
Measured outcomes and operating economics
When improved washing, inhibitors, pH control, and higher‑grade alloys are combined, salt and acid fall to very low levels. One plant reported ~98% salt removal — leaving ≈0.27 mg/L (milligrams per liter) NaCl in the crude — under thorough chemical dosing (researchgate.net). In that operating window, crude unit overheads showed negligible chlorides and very low iron pick‑up (well under 1 mg/L). By contrast, without careful pH/inhibitor control, brine pH can sag to ~5.5–6.0 and units start leaking within months.
The economics are blunt. Preventing even a single acid‑corrosion leak in a crude heater — a multi‑day shutdown at $100k/day — typically justifies the spend on chemical piping and control systems many times over. Industry write‑ups and vendor case histories confirm the principle: keeping wash water pH near neutral (ogj.com) (researchgate.net) and injecting film‑forming amines reduces corrosion rates by >90%.
Sources embedded above include industry guidance and case studies from ogj.com, integratedglobal.com, digitalrefining.com, and peer‑reviewed and technical papers on researchgate.net (all URLs preserved inline).
