Claus sulfur recovery units (SRUs) live or die on feed quality: predominantly H₂S, bone‑dry, and almost devoid of ammonia or heavy hydrocarbons. Getting there demands rigorous cooling, knockout, and gas‑service piping designed like a high‑hazard system.
SRU feed gas specification (Claus process)
The sour‑water stripper (SWS) must deliver acid gas that is mostly hydrogen sulfide (H₂S), with Claus units in practice requiring ≥15% H₂S by mole; leaner gas must be enriched or flared (nepis.epa.gov). The feed should be dry and free of entrained water or solids to avoid operational problems, with practitioners keeping gas above ~75 °C to avoid ammonium bisulfide (NH₄HS) deposition (bcinsight.crugroup.com).
Guidelines also call for cooling and knock‑out so the acid gas enters the Claus at ≲325 K (~50 °C), ensuring most condensables are removed (nepis.epa.gov). Any residual ammonia (NH₃) or hydrocarbons must be minimal: even a few percent NH₃ can upset Claus reactions and may require a two‑zone furnace or oxygen enrichment (patents.google.com). In short, the SRU feed should be a mostly H₂S stream with no free liquid, minimal NH₃ (ideally <0.01% v/v), and virtually no heavy hydrocarbon vapors (nepis.epa.gov; patents.google.com).
Where H₂S is below spec, operators co‑feed amine/HCl streams or concentrate the acid gas (nepis.epa.gov). NH₃ should be very low; if present, the SRU furnace must reach ~2800–3200 °F (1538–1760 °C) in a reducing first stage to destroy it (patents.google.com). Feeds from phenolic/hydrotreated streams can contain up to ~50% NH₃, prompting separate ammonia strippers or incinerators (patents.google.com; patents.google.com).
The feed must avoid liquid water carryover because the Claus reaction forms fresh water and any liquid can wash out SO₂ and drive corrosion; sour gas lines are kept above water and salt dew points, with one rule of thumb at ≥75 °C to avoid ammonium salt deposition (bcinsight.crugroup.com). Hydrocarbons—especially C₅⁺—should be virtually absent to avoid soot and catalyst coking, with knock‑out and cooling to ~325 K to remove heavy ends (nepis.epa.gov). Other impurities (COS, CS₂), particulates, solids, and oxygen should be essentially zero to avoid explosive mixtures.
Industry experience shows improper acid gas quality drives NH₄ salts and coke formation when SWS gas is not pretreated (patents.google.com), so licensors specify strict feed specs; off‑spec SWS gas is flared or incinerated.
Cooling and knock‑out pretreatment
Meeting those specs starts with cooling and separation. The hot stripper overhead (often 80–100 °C) is cooled via exchangers or atmospheric heat rejection well below water/hydrocarbon dew points—≲325 K—so liquid precipitates, followed by a knockout drum to remove the condensed liquid (nepis.epa.gov). The liquid—sour water, oils, or phenols—is withdrawn and typically returned to sour‑water tanks; the gas is then reheated or steam‑traced to prevent recondensation.
Demister pads and coalescing filters are standard to capture microdroplets, with a well‑designed knockout and filter train essential to avoid amine foaming and Claus catalyst fouling (petroskills.com). Coalescing elements are commonly packaged in steel filter housings for industrial service (up to 150 PSI) where pressure and temperature cycles demand robust construction.
Key pretreatment design notes include sizing the separation drum for slug handling and residence time, often combining it with a low‑pressure seal (water trap) serving the flare system (nepis.epa.gov); re‑heating or tracing to keep acid gas above problematic dew points (with operations maintaining >75 °C to avoid NH₄H(S) deposition; bcinsight.crugroup.com); and chilling when C₂–C₆ are present, though refinery SWS gas typically has little condensable hydrocarbon and is handled by the same drum.
For fine aerosol polishing or when sanitary‑grade internals are preferred, coalescers can be installed in 316L stainless steel cartridge housings to protect downstream SRU burners from droplets.
If ammonia is part of the SWS gas, a small ammonia stripper (circa‑ambient‑pressure column) can separate NH₃ into overhead for incineration or recycle, leaving a high‑purity H₂S stream to Claus—common in two‑stage SWS designs (bcinsight.crugroup.com). Indonesian guidance stresses removing sour gas water and oil to prevent downstream blockage (ppsdmmigas.esdm.go.id).
Piping materials and corrosion standards
The acid gas line is designed for high toxicity, flammability, and corrosion. Materials follow NACE/ISO standards for H₂S service—carbon steels or alloys that avoid sulfide stress cracking per NACE MR0175/ISO15156—with typical 3–5 mm corrosion allowance (osha.gov). Flanges, valves, and bolting are H₂S‑qualified (NACE MR0103) with low‑temperature toughness; the governing piping code is ASME B31.3 with Class D service limits.
Modern standards prohibit carbon steel above about 50 °C when P(H₂S) >0.05 bar (per NACE annexes); higher‑alloy steels are used when this is exceeded. All welds and joints are specified for H₂S service, and hardness controls are enforced (osha.gov).
Layout, drains, and instrumentation
Piping runs are kept short and sloped to avoid liquid pockets; vertical rises employ steam tracing, and all low points are trapped and valved. Multiple acid‑gas sources are combined only at a block‑valve manifold, with each branch using a double block‑and‑bleed configuration for maintenance.
Pressure relief valves (PRVs) upstream protect the line and any compressor, each venting via a dedicated line to a flare or combustor through its own knockout drum; the flare KO drum, often integrated with a water seal, scrubs liquids from blowdowns (nepis.epa.gov).
Gas detection and alarm setpoints
Odorless H₂S means fixed gas detection is mandatory along the piping and near the SRU inlet, with alarms setry at ~10 ppm; any leak triggers automatic emergency shutdowns including inlet valve closure, compressor shutdown, and overpressure flare activation (osha.gov). Personnel carry H₂S personal alarms and must evacuate at 10–15 ppm (NIOSH REL) (osha.gov).
Relief, flare, and fire protection
H₂S is extremely flammable with a 4–46% lower flammable limit (LFL), which drives physical separation from other equipment and the use of flame arrestors on vents (osha.gov). Any abnormal overpressure in the SRU feed header is relieved to a designated flare stack via a knockout/seal drum and block valves (nepis.epa.gov).
Because H₂S oxidizes to toxic SO₂ when burned, flare horsepower is sized for complete combustion, with oxygen enrichment used if needed.
Inspection, integrity, and work controls
Corrosion monitoring uses ultrasonic thickness (UT) probes or coupons to check for sulfide corrosion under insulation (CUI) every 3–5 years; inspectable joints employ trap collars or dog‑bone welds for hardness checks. Supports and layout accommodate thermal expansion (often a hot system) and seismic codes.
Above‑ground lines in populated zones are oversize (schedule 160 or higher) because H₂S service reduces allowable stress; buried sections use coated or cathodically protected steel per area standards. Hot‑work on H₂S lines is restricted and done only after purging with nitrogen to <10 ppm H₂S.
Safety practices follow Indonesian and international OSHA/API rules, including work permits, periodic leak surveys, and H₂S training (API RP 49/ANSI Z390). Alarm levels (10 ppm) and escape respirators are enforced, with warning signs and restricted‑area fencing in place; leak response includes fixed deluge systems and neutralization scrubbing for H₂S drains. Every pressure test or maintenance event purges the line with inert gas and verifies <1 ppm H₂S before entry (osha.gov).
Source notes and operating takeaway
Claus feed specifics and pretreatment are supported by refinery design experience and EPA Claus process guidelines (nepis.epa.gov; nepis.epa.gov). Safety practices draw on OSHA regulations and NACE materials standards (osha.gov; osha.gov). Indonesian references underscore sour‑gas corrosion hazards (ppsdmmigas.esdm.go.id).
