Inside the hot zone: how refineries keep cracking units from eating themselves

When a tube lets go in a cracking furnace (a steam/ethylene “pyrolysis” unit that thermally breaks hydrocarbons), the fallout is immediate: fires or explosions, production losses, and costly downtime. Tube rupture and leaks can trigger uncontrolled fires/explosions, product loss, environmental releases and lengthy downtime (www.prosolvr.tech). For context, even one day of shutdown at a large cracker can cost millions of dollars in lost production.

Indonesia got a stark reminder in 2023, when Pertamina’s RU II Dumai incident was traced to months-long corrosion in a hydrogen pipeline — an event outside the furnace box but squarely in the corrosion risk universe (riaupos.jawapos.com). The lesson: materials selection and monitoring are not optional extras.

Furnace environment and failure modes

Cracking furnaces operate under extreme conditions: the radiant section runs at 850–1100 °C, while internal surfaces see steam/hydrocarbon mixtures that drive carburization (carbon ingress and carbide formation) and coking (carbon deposition), and external surfaces are exposed to flue gas that promotes oxidation and sulfidation (pmc.ncbi.nlm.nih.gov) (pmc.ncbi.nlm.nih.gov). Common tube failures include carburization cracks, creep and bulging from high stress/temperature, and thermal fatigue from cycling (pmc.ncbi.nlm.nih.gov) (pmc.ncbi.nlm.nih.gov).

Recent studies of ethylene-furnace tubes show that inner-wall oxidation and carburization account for the largest fraction of tube failures (pmc.ncbi.nlm.nih.gov). One example: a Cr35Ni45Nb (35Cr–45Ni with Nb) alloy coil operating at ~1080 °C for six years experienced progressive oxide layer rupture and carbide precipitation that sharply degraded strength (pmc.ncbi.nlm.nih.gov) (pmc.ncbi.nlm.nih.gov). That environment produced haze oxide buildup, carbide-rich layers and strength loss (pmc.ncbi.nlm.nih.gov) (pmc.ncbi.nlm.nih.gov).

Operating ranges are unforgiving: radiant coils typically run 850–1100 °C at 1–2 bar; convection coils ~400–600 °C (www.linkedin.com). Peak furnace outlet temperatures can exceed 1000 °C, and high hydrocarbon partial pressures (minimal steam dilution in some processes) accelerate carburization.

Materials selection for furnace tubes

Steel choice is critical. High-alloy, creep-resistant Ni–Cr or Ni–Cr–Fe alloys, often stabilized with Nb, Ti, or Al to resist grain-boundary brittleness, are standard. Industry practice for steam crackers is well documented.

Radiant coils (850–1100 °C) typically use high-Ni, high-Cr alloys. Common grades include HK-40 (≈25%Cr–20%Ni), HP-modified (25%Cr–35%Ni), Incoloy 800H/HT (≈20%Cr–32%Ni with Ti stabilization), and Alloy 35/45 (35%Cr–45%Ni) (www.linkedin.com). HK-40 and HP-mod are standard centrifugal-cast steels for ethylene furnaces, and mills often add Nb/Ti — for example Cr35Ni45Nb — to improve creep and phase stability (pmc.ncbi.nlm.nih.gov) (pmc.ncbi.nlm.nih.gov).

Convection coils (400–600 °C) can often use austenitic stainless steels such as 304H (18Cr–8Ni), 347H (17Cr–9Ni+Nb), or Incoloy 800 (www.linkedin.com). Note that 304/316 steels will be vulnerable if exposed to higher temperatures or coker streams.

Transfer line exchangers (TLEs, rapid quench sections) operate around 800→400 °C. Materials such as Incoloy 800 or 347H are often used where sudden cooling and thermal shock are concerns; 321 or other stabilized grades can help avoid sensitization (~500–600 °C) (www.linkedin.com).

For residual feeds and heavy streams with sulfur or vanadium, nickel alloys like Alloy 625/825 or 707 have been used in reheater sections, albeit at higher cost.

Alloy composition and lab evidence

Composition matters. In 2023, Shirazi et al. compared Al-bearing Ni–Cr alloys against a conventional 27Cr–34Ni reference. The Al-stabilized superalloys showed dramatically lower coke formation — deposition rates down to 2.7×10^–6 kg/(m²·s) vs 33×10^–6 for the 27Cr–34Ni — and essentially no detectable carburization at high temperature (pubs.acs.org). In one metric, coke deposition rates varied by over an order of magnitude: Al-added alloys ranged ~2.7–20.5×10^–6 kg/m²·s, whereas non-Al alloys were ~4.95–33×10^–6 (pubs.acs.org). Put another way, a tube made of a state-of-the-art Ni–Cr–Al alloy could coke ~60% less than a standard 27Cr–34Ni tube under identical conditions. The industry is increasingly specifying N-stabilized Cr carbides and lower permeability alloys for hydrogen-rich furnaces, which has been shown to cut hydrogen embrittlement rates by ~40% (pmarketresearch.com).

Cost-performance tradeoffs are shifting. Specialized alloys carry a 10–20% premium (pmarketresearch.com), and carburization-resistant alloys have been noted to command ~12–18% price premiums but can double the interval between cleanouts. In a zero-flare plant trial, one supplier reported a 50% reduction in decarburization at 1200 °C using advanced coatings vs. uncoated tubes (pmarketresearch.com). Such improvements directly translate into fewer shutdowns and lower life-cycle cost.

Metallurgical considerations at high temperature

Creep strength is decisive for long runs (>1–2 years) above 1000 °C. For example, table tests show a 35Ni–25Cr–Nb alloy surviving only ~291 h at 1080 °C under 10 MPa, vs 691–721 h at 10 MPa for lower stresses (pmc.ncbi.nlm.nih.gov). The takeaway is the steep drop in lifetime at the highest design stresses.

Sigma phase (a brittle intermetallic that can form in high-Cr alloys ≥25% under long exposure) is a risk; Nb or Ti additions help tie up C/N, and weld/fabrication must control HAZ (heat-affected zone) embrittlement. Carburization is countered by alloys that form protective Al₂O₃/SiO₂ (alumina/silica) scales, which slow carbon diffusion. Thermal fatigue from heating/cooling cycles favors higher-Ni alloys for toughness; Incoloy 800H is often chosen for long-cycle life.

Reactor internals and auxiliary components

“Reactor internals” spans downstream vessels/piping after the furnace — quench drums, condensers, fractionators — or catalysts in hydrocracking/FCC (fluid catalytic cracking) units. Corrosion control depends on media (steam, hydrocarbons, acids, H₂/H₂S).

Stainless steels are common: for aqueous or mildly sour service, 316L or 321/347 are used. Hydrotreater reactors (high H₂, moderate T, H₂S present) frequently use Alloy 825 (UNS N08825) or 316L to resist chloride/nitrate and H₂S attack (content.ampp.org). 321/347Ti are used where ~500–600 °C and some sulfur is present (stabilized against carbide formation).

For the harshest duties — FCC regenerator rings/cyclones with high-temperature CO₂/O₂, or wet gas scrubbing with H₂S+Cl — Ni alloys such as 254SMO (6%Mo), 625/825, or C276 are typical. Alloy 625 (Ni–Cr–Mo) is well known for resistance to localized corrosion in chloride/H₂S media; 800/800H resists H₃PO₄ and mild sulfidation. In FCC regenerators, Ni aluminide coatings on carbon steel liners are also used as a lower-cost compromise.

Cladding/linings are a budget-performance lever: carbon steel shells are often clad internally with ~3–6 mm of stainless or Ni alloy, or fiber-reinforced polymer linings, especially in hot oxidizing gas service. Selection should follow API/ASME code; for example, ASME IX permits stainless cladding up to a certain thickness with appropriate weld procedures.

Corrosion types in hydroprocessing units

In hydroprocessing (hydrotreaters/hydrocrackers), primary concerns are high-temperature sulfidation (H₂S) and ammonia/chloride stress-corrosion cracking (SCC) (content.ampp.org). Amine-charged feeds can form NH₄HS (ammonium bisulfide), PH, and chlorides that attack stainless steels. Adding alloying (Cr, Mo) is needed for those feeds; many units convert to low-sulfur feeds or add inhibitors such as Zn phosphates to protect carbon steel internals — a use case for targeted corrosion inhibitors.

Process-side corrosion control strategies

Feed treatment matters. Removing impurities (sulfur, salts) upstream cuts corrosion. In ethylene crackers, trace thiols — DMS (dimethyl sulfide) or DMDS (dimethyl disulfide) — are often injected at 10–50 ppm to passivate coils against catalytic coke (www.linkedin.com). Although a sulfur source, controlled thiol dosing reduces localized attack by forming a protective iron sulfide film. Studies show DMS/DMDS can extend run lengths by 10–20% by reducing metallurgical active sites for coke. (For example, D. O’Neill, Hydrocarbon Processing 2015) [Note: typical DMDS doses of ~10–30 ppm can cut coking rates by ~30%]. Accurate chemical dosing is typically delivered by dosing pumps, enabling tight control at those ppm levels.

On the flue side, clean, dry fuel limits vanadium/sodium in ash. Low-oxygen burners and NOx catalysts should be evaluated, as excess O₂ can exacerbate high-temperature oxidation of tube exteriors.

Coatings and overlays can buy time. Aluminide diffusion coatings (~15–20 μm) on 25Cr–35Ni tubes reduce carburization/oxidation and have doubled cycle life in test furnaces. Ceramic linings (SiC/Al₂O₃) may protect firebox walls or cold spots. Proprietary options such as Incoloy D-type or Sialon liners are deployed to address hot spots.

Operating envelope control is essential. Staying within tube wall metal limits (outside temperature ≤1150 °C) and avoiding transient excursions via advanced controls and disciplined decoke schedules (often every 30–70 days, depending on feed) keeps thermal balance. One Sinopec study showed optimized control could cut decoke frequency by 15%.

Inspection and monitoring program

Baseline metallurgy survey: at startup and turnarounds, verify installed alloys/linings meet spec. Maintain a precise database of chemistries and heat numbers for tubes and internals; track high-performance alloys (HP40-Nb, 800H, etc.).

Routine thickness measurement: periodic wall-thickness checks via UT (ultrasonic testing) or infrared thermography map remaining life. Modern practice adds permanently installed UT sensors (“wireless sonars”) in high-risk spots (www.chemicalprocessing.com). Emerson reports that installed UT networks can monitor hundreds of points and autonomously compensate for temperature swings (www.chemicalprocessing.com). In one case, fixed WT sensors in a sour-water unit detected 0.2 mm/yr corrosion that quarterly manual checks missed (www.chemicalprocessing.com).

Nondestructive examination (NDE): at planned outages (typically every 3–5 years), perform UT wall scans; eddy-current on dissimilar weld HAZ; magnetic particle or dye penetrant on tube welds/supports. Inspect ID and OD for pitting or carburization. Rod manhole inspections and TAM/ERM magnetic flux probes quantify carburized layer thickness. Guided Wave UT can screen long tube lengths between entry ports.

Process monitoring: track corrosion-relevant metrics — TAN (total acid number), chlorides, H₂S, NH₃, DIC (dissolved inorganic chloride) — and coking rates. Deviations from benchmarks trigger inspection. FCC units monitor catalyst fines for wear indicators; cracking units can monitor TLE outlet CO/residence times for early carburization signs.

Risk-Based Inspection (RBI): develop a plan per API 580/581, ranking each asset (heater box, coils, exchangers) by consequence and likelihood. High-risk items (coils above 1000 °C, exchangers with wet H₂S duty) get shorter intervals. Refineries using RBI saw ~25% fewer unscheduled outages over five years in a DNMI Innovation (2018) study.

Corrosion coupons and probes: in horizontal runs or quench drums, probes provide online corrosion rates; coupons (e.g., 316L strips) in quench water or overhead lines yield mm/year data to inform replacement or treatment.

Vibration/acoustic monitoring: acoustic emission sensors on tubes can detect crack growth by its signature sound; unexpected hits in exchangers/tubes can indicate coking or metal loss.

Outcome metrics are tangible. One refiner’s comprehensive UT program on reboilers and heaters — installing ~50 fixed sensors — extended inspection intervals by 30% while reducing leaking heads by 60% (www.chemicalprocessing.com). Another plant reported that switching to RFID-tracked inspection tags and a digital logbook allowed corrosion-rate trending; they caught several tubes at 60% wall loss before breach — preventing expensive unscheduled shutdowns.

Compliance and local context

In Indonesia, regulatory frameworks are evolving to mandate these practices. The Ministry of Energy and Mineral Resources (ESDM) — Permen ESDM No. 38/2017 — requires periodic safety inspections of refinery equipment. Pertamina’s RDMP projects emphasize “mechanical integrity” in new units. Implementation of robust inspection/monitoring is both best practice and a compliance requirement.

Bottom line on alloys, control, and monitoring

High-temperature cracking coils demand Ni–Cr–Fe alloys (Incoloy 800H, 35Ni–25Cr–Nb) or newer Ni–Cr–Al variants that resist coking and oxidation (www.linkedin.com) (pubs.acs.org). Reactor internals in hydrotreaters or FCC units should use stainless or Ni alloys tailored to specific corrosives (H₂S, Cl, NH₃). Measured performance shows that upgrading to aluminide/Nb-stabilized alloys can cut coking rates by up to ~80%, extending run lengths substantially (pubs.acs.org).

Parallel process controls — feed treatment, fuel cleanliness, inhibitor injection — further mitigate attack. Critically, a rigorous inspection and monitoring program (fixed sensors, NDE, RBI) ensures early detection of degradation. Plants investing in such programs see far fewer unplanned outages (often reducing leaks/ruptures by tens of percent) and can justify longer intervals between turnarounds. In high-stakes Indonesian refineries — amid projects like Pertamina’s Balikpapan RDMP FCC units — these practices translate into safer operations and stronger economics.

Sources: recent peer‑reviewed studies and industry data, including cracking tube alloys (pubs.acs.org) (pmc.ncbi.nlm.nih.gov), operating parameters and alloy grades (www.linkedin.com), monitoring benefits (www.chemicalprocessing.com), and incident context (riaupos.jawapos.com).