Crude preheat trains foul fast, slashing heat transfer and throughput — and one case put the annual fuel penalty at about $5.4 million. A field‑tested playbook of upstream desalting, antifoulant dosing, and chemical cleaning is shifting the economics.
Crude oil doesn’t arrive clean. It brings water, dissolved salts, suspended solids, and heavy organics such as asphaltenes and waxes, all of which are primed to deposit when heated in a preheat train (digitalrefining.com) (fqechemicals.com). The result is a stubborn, dual‑layer mess — often ~50% inorganic scales (iron/silica) and ~50% organic mass (asphaltenes/waxes) by weight — that drags down performance (digitalrefining.com) (fqechemicals.com).
As deposits accumulate, the exchanger’s overall heat‑transfer conductance (UA, a measure of how effectively a unit transfers heat) falls, approach temperatures tighten, and pressure drop rises; required furnace duty climbs to compensate (cheresources.com) (fqechemicals.com). In one assessment, fouling drove roughly $5.4 million per year in extra fuel, before counting throughput losses (researchgate.net). Even a few °C of added duty can trim distillation throughput by a few percent, with significant profitability impact (digitalrefining.com) (researchgate.net).
Preheat‑train contaminants and penalties
Upstream, desalting and solids control are the first line of defense. Electric‑pulse water wash desalting reduces chloride and particulate carryover into hot exchangers, curbing both inorganic scale and organic deposition (digitalrefining.com) (cheresources.com). On blending, “stability” matters: incompatible mixes of heavy and light crudes can precipitate asphaltenes. Simple compatibility tests (e.g., solvent deposition trials or solubility blending number) help avoid combinations that flocculate when heated.
Refiners have also leaned on high‑aromatic diluents to stabilize heavy feeds. Patents describe adding small fractions of high‑solvency aromatic crude to keep asphaltenes dissolved (SBN, or solubility blending number, >80) and flush deposits; one soak with a high‑SBN blend lifted feed preheat by ~15 kbtu/bbl (≈100 kJ/L) on average (patents.google.com) (patents.google.com). In short, design blends so SBN to insolubility number (Iₙ) exceeds ~1.0, or co‑inject aromatic diluents to maintain solubility (patents.google.com).
Antifoulant injection and field performance
Continuous antifoulant dosing upstream of the preheat train disperses potential foulants before they stick. Most additives are surface‑active surfactants or polymers that solvate or encapsulate asphaltene and wax particles (e.g., alkylphenol ethoxylates, olefin sulfonates, polyamide amines, polyisobutylene succinimides, naphthenic acid derivatives; formulations are typically proprietary) (researchgate.net). In pilot work, a magnesium‑sulfonate surfactant with nanocarbon additives cut deposit mass by ~90% (about 1 g vs ~23 g without additive) and halved pressure drop (1.1 vs 2.5 psi), with fuels saved and crude conversion up by ~2–3 wt% post‑installation (researchgate.net) (researchgate.net).
Results vary. An experienced engineer cautions that off‑the‑shelf antifoulants sometimes only reduce fouling 10–15% unless the chemistry matches the crude and conditions (cheresources.com). That’s why field trials at process conditions (continuous‑loop tests) are favored over lab coupons, which can overpredict benefits (researchgate.net) (digitalrefining.com).
In practice, additives are injected continuously at low dosage — often tens to hundreds of ppm — at a point that ensures good mixing and entry to the hottest exchangers. Accurate metering with a dosing pump supports tight control of the rate. Vendor guidance and crude assays typically set the initial dose; operators then watch UA or pressure‑drop trends to fine‑tune. Overdosing can trigger emulsion issues or excessive carryover. Residuals must be compatible with downstream catalysts and wastewater limits (researchgate.net).
Operational controls and deposit disruption
Beyond chemistry, temperature discipline matters. Keeping tube‑wall superheats in check and managing throughput so the hottest exchanger sits below the onset temperature for asphaltene precipitation help avoid thermal polymerization and deposition. Some units also run on‑stream rinses — diverting desalting water or steam through exchangers to melt waxes and wash away salt scales — as a quick intervention (cheresources.com).
Others have added ultrasonic transducers to exchanger shells. Low‑power ultrasound has been reported to “poke” fouling loose and improve uptime; one vendor claims 24/7 disruption of deposits and up to ~100% cleanability without shutdown (digitalrefining.com).
Chemical cleaning in place (CIP) loops
When fouling crosses limits, online cleaning can keep barrels moving. If the train is set up with isolation valves and a cleaning loop, operators can circulate cleaning fluids through exchangers without a full shutdown; this “CIP” (clean‑in‑place) design “allows cleaning without shutting down” (epcmholdings.com).
Cleaning chemistry is staged by foulant type. A mild solvent or alkaline detergent targets organic layers first; then a separate acid or chelant phase tackles inorganics. One approach circulates a hot hydrocarbon or glycol solvent to dissolve asphaltenes, followed by a dilute inhibited acid (e.g., phosphoric/nitric) to chelate iron salts, with the crude by‑passed during the cycle (epcmholdings.com). In one case history, an in‑line solvent soak using a high‑solvency light crude restored furnace feed temperature by 15 kbtu/bbl (patents.google.com). A final flush with clear hydrocarbon or water removes spent chemicals before normal service resumes.
Offline turnaround cleaning sequence
Severe fouling or bundle access needs trigger an offline job. Standard practice uses a fill‑and‑soak sequence, warmed and circulated, with steps for both organics and inorganics:
Step 1 — Pre‑flush (solvent): Fill with hot hydrocarbon (e.g., recycled kerosene or diesel) or a surfactant emulsion to dissolve the hard “black pancake” of asphaltenes and wax, circulating for hours to soften organics. Solvent steps that target waxes can be supported by products designed to dissolve paraffin wax deposits, such as a wax dissolver.
Step 2 — Alkaline soak: Drain and circulate an alkaline detergent (e.g., sodium hydroxide with a surfactant or an amine detergent) at 50–80 °C to saponify and wash away oils, greases, and fragmented organics (xylemheattransfer.com).
Step 3 — Acid/chelating soak: After a flush, fill with inhibited acid (commonly phosphoric/nitric mixtures) or an organic chelant (e.g., a citric/acetate blend referenced in WO2015044709) to dissolve iron oxides, calcium carbonate, and metallic salts (xylemheattransfer.com) (fqechemicals.com). Soak until reaction slows and sample effluent for hardness.
Step 4 — Final rinse: Thoroughly flush with fresh water (if the system is demulsified) or solvent; neutralization steps (e.g., with bicarbonate) may be required between stages to avoid violent reactions. Step 5 — Reassemble and test: Dry/purge, restart, and monitor performance.
These deposits are “not coke, but very tenacious carbonates and resins,” and solvating the organic binder is often the rate‑limiting step; once the binder is broken, inorganics flush or dissolve more easily (fqechemicals.com) (fqechemicals.com). Hydroblasting or steam cleaning can complement chemicals, with care to avoid tube damage. In one report, flushing with light hydrocarbons (kerosene/diesel) recovered 80–85% of lost capacity during outage cleanup (digitalrefining.com).
Waste handling and regulatory notes
Spent acids/caustics and oily sludges require compliant disposal. For example, Indonesia’s environmental rules classify these as hazardous waste (B3), so post‑cleaning neutralization and permitted discharge or contractor removal are required according to local permits.
Monitoring and ROI: best‑practice checklist
- Monitor fouling metrics: Use heat‑transfer models or alarms on ΔT (approach temperature) or pressure drop to act before performance loss becomes prohibitive.
- Optimize desalting: Keep crude water and salt content as low as possible; ensure wash‑water quality (e.g., <5 mg/L solids) to reduce carry‑through.
- Blend for stability: Avoid high‑ΔT mixing of incompatible crudes; consider aromatic diluents or high‑SBN streams for heavy feeds (patents.google.com).
- Maintain small continuous doses of antifoulant: A well‑chosen dispersant injected at pump suction can extend run length; validate vendors’ claims with field trials (researchgate.net) (researchgate.net).
- Water‑wash tactic: Periodic on‑line desalting‑water or steam flushing can dislodge salt scales in exchangers (cheresources.com).
- Enable CIP design: Where feasible, equip preheat loops with circulation circuits and isolation valves to clean on‑stream with detergents/acids (epcmholdings.com).
- Plan turnarounds: Execute the fill/soak sequence rigorously — solvents/detergents for organics first, then acids for inorganics (fqechemicals.com) (xylemheattransfer.com).
- Quantify gains: Document recovered UA and ΔP, and track ROI. Eliminating fouling may recover several tens of kJ/kg of crude heating value (patents.google.com) and boost throughput by ~2–3% (researchgate.net), often outweighing chemical costs.
By combining aggressive fouling‑inhibition chemistry with disciplined operations and periodic chemical cleaning, refiners can materially reduce the productivity and energy penalties of preheat‑train fouling (researchgate.net) (patents.google.com). The choice of antifoulant and cleaning regimen is crude‑ and configuration‑specific, and best validated by pilot tests and monitoring to secure measurable gains.
Sources: Peer‑reviewed studies and industry data on crude‑train fouling and chemical cleaning (digitalrefining.com) (fqechemicals.com) (researchgate.net) (researchgate.net); case studies and patents on solvent‑soak interventions (patents.google.com) (researchgate.net); industry experience and best‑practice reports (digitalrefining.com) (cheresources.com) (epcmholdings.com). All figures and claims are from these cited sources.
