In ammonia and urea plants, steam‑methane reformers run on nickel catalysts that need to hold 95–97% methane conversion. Even ppm‑level sulfur or a hint of coke can slash hydrogen yield and drive up fuel bills.
In ammonia/urea synthesis, steam‑methane reformers (SMRs, high‑temperature reactors that convert methane and steam to hydrogen and carbon monoxide) lean on nickel catalysts—typically Ni/Al₂O₃ or Ni spinel—to turn natural gas into syngas (CO+H₂). The target is near‑equilibrium methane conversion of roughly 95–97%, and a typical steam/carbon (S/C, molar steam‑to‑carbon ratio) feed split of 85% H₂O and 15% CH₄ can deliver ≈95% CH₄ conversion (ScienceDirect).
Any deactivation—poisoning, coke, sintering—cuts hydrogen yield and raises fuel cost. Modern SMRs are built for multi‑year service, yet small losses reduce capacity and increase consumption; each 1% drop in conversion may cost ~$X million/yr on a 3 MTPD NH₃ plant.
Sulfur poisoning and site blocking
Sulfur is the outsized risk. Sulfur compounds in feed (mercaptans, H₂S, etc.) convert at reformer temperatures to H₂S, which chemisorbs strongly on nickel, blocking active sites (ScienceDirect; ACS Omega). Nickel rapidly forms a Ni–S surface (≈0.5 S/Ni stoichiometry, or ~440 µg S per m² Ni, ScienceDirect), collapsing activity. In practical terms, even ppm‑level H₂S can cripple the catalyst; “ppm levels of sulfur impurities [in the feed] reduce the life of commercial catalysts to only months or weeks” (ACS Omega).
The real‑world backdrop can be harsh: one Indonesian study measured ~3 ppm H₂S in raw feed gas (ResearchGate). Without deep scrubbing, that level rapidly saturates a Ni surface.
Carbon formation and S/C control
Carbon formation (coking) is the other major threat. At 750–820°C, methane and heavier hydrocarbons can crack thermally (e.g., CH₄ → C + 2H₂), laying down graphite on the catalyst (Gas Processing News; ProcessPhase). Left unchecked, carbon “whiskers” pierce pellets, drive up tube pressure drop (ΔP, the pressure difference across the catalyst bed), and trigger hot spots where reaction stalls.
Operation aims to make carbon‑removal reactions (CO + H₂ → C + H₂O; 2CO → C + CO₂) outpace cracking. Feed composition and S/C are decisive: practical experience shows pure methane feeds require S/C ≈1.7–2.0 to avoid carbon buildup, while heavier naphtha needs ~2.2+ (Gas Processing News). In modern ammonia service on methane, S/C of ~3:1 is standard (Gas Processing News), giving margin against coke at ~800°C.
Catalyst promoters help. Alkaline additives (Ca, Mg, K) enhance carbon gasification; adding Ca or Mg can cut the minimum required S/C by ~16%, and strong alkali (K) can lower it by ~65% by accelerating carbon‑removal rates (Gas Processing News). In one UK trial, a potassium‑promoted reformer catalyst ran 9 months with little carbon deposit, while an unpromoted unit showed hot bands after only a few months (Gas Processing News).
Other deactivation modes and monitoring
Nickel can sinter (particle coalescence at high temperature/steam), bleeding surface area (ScienceDirect). Mechanical attrition from vibration or thermal expansion breaks pellets. Impurity fouling—trace Cl⁻, for instance—can oxidize and block sites. A special hazard: Ni catalysts should not see CO at low temperature (<200°C), where toxic nickel carbonyl Ni(CO)₄ can form (Scribd).
Plants track health via outlet CH₄ slip (unconverted methane percentage) and reformer tube ΔP; rising CH₄ slip or the appearance of cold “hot bands” beyond specifications prompts catalyst replacement.
Gas cleanup train design and targets
Given nickel’s sulfur sensitivity and coking tendency, robust upstream purification is non‑negotiable. Industry practice is multi‑stage: bulk acid‑gas removal via amine (e.g., MDEA), followed by a ZnO (zinc oxide) “guard bed” for tail‑end H₂S polishing to essentially zero sulfur at the reformer inlet. An ammonia procedure notes a ZnO bed can cut H₂S to <0.1 ppm (ppm, parts per million), and is deemed “spent” at ~0.2 ppm slip (Scribd). That spec matters because even 0.1–0.5 ppm H₂S can gradually poison Ni.
Quantitatively, dropping raw‑gas H₂S from ~3 ppm (Indonesian feed, ResearchGate) to 0.1 ppm is a 30× reduction. Studies indicate that taking H₂S from tens of ppm to sub‑ppm extends catalyst life from mere months to multiple years (ACS Omega; Scribd). In Indonesia, where Sumatran gas basins can vary in H₂S, operators typically specify gas sales quality (e.g., <1 ppm H₂S) under Ministry of ESDM guidelines to protect downstream plants; a PT Pupuk Sriwidjaja survey found ~3 ppm H₂S in raw pipeline gas (ResearchGate), which would not be acceptable at the reformer inlet without purification.
Beyond sulfur, plants remove organic chlorides (via hydrocarbon treaters) and fine particulates (via coalescers). CO₂ is usually only partially removed in the amine scrub, since some CO₂ in syngas is needed for the water‑gas shift. Feed gas heaters sometimes include molecular‑sieve beds to remove moisture and mercury (the latter poisons downstream catalysts). In design simulations, MDEA scrubbing can cut 10–1000 ppm sour gas to <10 ppm; a ZnO bed then “polishes” to ≈0.01 ppm H₂S (Scribd). Key metrics are residual H₂S (<0.1 ppm) and hydrocarbon dew point (e.g., <–10°C). Daily monitoring is standard; ZnO breakthrough (slip >0.1 ppm) triggers immediate replacement.
For bulk acid‑gas removal, operators commonly specify amine systems; a regenerable option is reflected in CO₂/H₂S removal amine solvent packages used ahead of ZnO guard beds. Coalescers that catch fine particulates are typically housed in pressure‑rated equipment; plants often standardize on steel filter housings for industrial service. Keeping spare media, seals, and internals on hand simplifies ZnO changeouts and routine upkeep, a role supported by water treatment parts and consumables.
What strong purification delivers
A clean feed shows up immediately in reactor data. Modern ammonia reformers achieve >95% CH₄ conversion at design load with exiting CO≈10–12% (ScienceDirect). When the catalyst begins to poison, outlet CO and CH₄ slip climb, and reformer outlet temperatures rise (unconverted methane carries heat). In one case without proper sulfur removal, outlet CO swung from 12% to 30% alongside rising tube wall temperatures (Cheresources).
Hitting the ZnO target (<0.1 ppm H₂S) maintains hydrogen purity and capacity: every 0.1% of CH₄ slip lost may lower plant H₂ output by ~0.2%. Plants that hold <0.05 ppm H₂S typically see catalyst cycles of 3–5 years, while those with higher trace sulfur often replace catalyst in under a year (ACS Omega; Scribd). The economics are clear: a single reformer reload (≈$1–2M) and a 2–3 week outage outweigh the ongoing operating expense of amine/ZnO scrubbing.
Catalyst loading and start‑up sequence
Catalysts arrive as pellets or extrudates, often in steel drums. Before loading, tubes and support grids are inspected; drums are handled with slings (not rolled or dropped). Open catalysts remain pyrophoric (especially prereformer catalysts with residual Ni metal), so loading under nitrogen purge is preferred. Using socks or tubular funnels, pellets are poured slowly—under ~3 feet of free‑fall per second—to limit breakage (SlideShare). ΔP is checked per tube during loading to keep packing density consistent; gentle vibration/tapping settles the bed and removes voids or bridging (SlideShare). Overfill or voids cause uneven flow; non‑uniform bed heights show up as temperature imbalances (“hot/cold bands”) and ΔP variations (SlideShare). After loading, plants record catalyst weight per tube, seal tube ends, and verify uniform distribution—<~5% variation in ΔP between tubes is typical.
Pre‑start checks include leak testing and nitrogen purging. The vessel is heated gradually (e.g., to 200–300°C) to avoid thermal shock and stage the reduction step; safety interlocks (S/C limit, fuel cutoff) are set, and feed purification (H₂S removal, water ejection) is confirmed online.
Most primary reformer catalysts are supplied as NiO (oxidic form) and require controlled reduction to metallic Ni. Two common methods are used. (a) Hydrogen reduction: introduce a hydrogen‑containing gas at ~50–100 Nm³/hr (Nm³/hr, normal cubic meters per hour) through the tubes; ramp furnace firing to ~350–450°C over several hours. At ~250–350°C, hydrogen flow begins; by 400–450°C the reduction exotherm is essentially complete. Off‑gas water is monitored to track progress. (b) Methane reduction: once tubes are hot, introduce a dilute CH₄/steam mix (<10% CH₄). The CH₄ reduces NiO exothermically, demanding slower ramping. Reduction typically continues 2–6 hours until oxygen in tailgas is <1% (O₂ analyzer), indicating full reduction. Pre‑reformers are often pre‑reduced passivated (PRP) and need only mild reduction.
After reduction, the startup sequence proceeds: 1) Heat‑up: bring the bed to operating temperature with burners fully fired and no hydrocarbon feed; maintain steam circulation and keep tubes above the steam dew point (the temperature where vapor condenses) before higher steam flows. 2) Steam introduction: start low steam flow; temperatures (often 350–400°C tube wall) keep steam fully vapor. In the absence of hydrocarbons, a small hydrogen addition (H₂:steam ~10:1) guards against Ni oxidation. 3) Natural gas feed: once the bed is uniformly hot (baseline CO <5%), gradually add methane/natural gas and ramp to design S/C (e.g., 2.8–3.5). Maintain steady outlet temperatures and ΔP; early operation is slightly fuel‑rich to prevent flameout. Typical temperature ramp rates are <50°C/hour to avoid hot spots. 4) Full load: as syngas analyses stabilize (CO ~10–12%, CH₄ <1%), steam and fuel reach design; downstream shift converters and CO₂ removal come online in sync.
Throughout, temperatures (burner and tube outlets), pressures, and syngas composition are monitored continuously. The catalyst should not see CO at <200°C to avoid Ni(CO)₄ formation (Scribd). The bed should not be flooded with cold steam or water. Large swings in S/C or abrupt fuel changes can crack pellets. Control logic generally interlocks on S/C so no feed gas is admitted until the desired Ξ (based on steam flow) is reached; many operators hold a minimum S/C (~2.5) to forestall coke.
On large reformers, a cold‑to‑full‑run startup typically takes ~24–48 hours. At steady state, plants verify CH₄ slip (<2–3% for 97% H₂ purity) and CO conversion (~3±1% residual). Uniform ΔP and outlet CO across tubes confirm good loading. Operating logs often show that meticulous loading and cautious ramping reduce initial attrition and maximize first‑run output.
Ongoing lifecycle management
Sustained performance hinges on feed gas quality (ZnO bed replacements on schedule) and S/C at or above design. Catalyst life is trended via outlet conversions and periodic tube inspections; under clean conditions, Ni‑based SMR catalysts typically run 3–5 years. If activity slips (higher CH₄ slip or a CO₂/H₂O ratio shift), a short offline burnout or steam purge can sometimes recover limited capacity. Ultimately, a full reload is required; the operating goal is to maximize runtime between reloads through prevention.
Sources and technical anchors
Authoritative texts and industry reports on steam reforming (e.g., Rostrup‑Nielsen via ScienceDirect; ScienceDirect), engineering guides on carbon control (Gas Processing News; Gas Processing News), Indonesian feed gas analyses (ResearchGate), plant operating manuals for ZnO specs (Scribd), peer‑reviewed reviews on sulfur poisoning (ACS Omega), loading practice (SlideShare), and safe startup/shutdown (Scribd) anchor the procedures and specs cited above. Inline citations are provided.
