The refinery workhorse turning “sour water” into reusable supply — and savings

Hydrotreaters and reformers churn out “sour water” — a wastewater rich in hydrogen sulfide (H₂S) and ammonia (NH₃) — that refineries must detoxify before reuse or discharge. Non‑phenolic hydrotreating effluent is almost entirely NH₃ and H₂S with little CO₂ (digitalrefining.com), and in practice feed molar H₂S:NH₃ ratios typically sit at 0.5–0.8 (digitalrefining.com). In contrast, phenolic sour water from coker/FCC units carries phenols and cyanides that survive stripping and are generally kept out of reuse because of catalyst corrosion risks (bcinsight.crugroup.com).

Design targets are set by how the refinery plans to reuse or discharge the water. Bottoms often aim at ≤1 mg/L H₂S and ≤10 mg/L NH₃ (mg/L = milligrams per liter) (bcinsight.crugroup.com). Many plants in the field accept NH₃ at ~30–80 ppmw (ppmw = parts per million by weight) while driving H₂S to essentially “undetectable” levels (<0.1 ppmw) (digitalrefining.com), roughly aligned with Indonesian PermenLH limits near ~10 mg/L ammonia–N and 1 mg/L sulfide (bcinsight.crugroup.com).

Sour water feed and pretreatment

Typical sour water arrives around 30–40 °C, is degassed and oil‑skimmed, and then pumped to the sour water stripper (SWS). Removing free oil before the column is standard practice to avoid fouling and reliability hits; refinery guidance flags oil contamination as a cause of capacity reductions and flaring upsets (pall.com). Upstream physical separation systems such as an API stage or screens can be packaged via primary oil and solids removal, and free oil is typically polished to low ppm using oil removal units.

Column design and steam duty

In the column, steam heats the water to boiling (~115–125 °C), stripping H₂S and NH₃ into the vapor. In a conventional reboiled design, lifting from ~32 °C to ~120 °C requires about 16 wt% steam — roughly 1.3–1.4 lb steam per gallon of bottom water (≈0.15 kg/L) — a typical steam‑to‑water ratio for SWS service (digitalrefining.com).

Overhead gases (acid gas plus NH₃) are routed to the sulfur recovery unit’s thermal reactor (also called a Claus incinerator), where residual H₂S/NH₃ are combusted prior to sulfur recovery (bcinsight.crugroup.com).

Direct steam vs. reboilers

Modern designs simplify the heat supply. Circulating‑thermosyphon or direct injection heaters can act as a “kettle” reboiler (pdfcoffee.com). Roughly 50% of refineries now inject low‑pressure steam directly into the stripper bottoms and abandon the kettle reboiler (pdfcoffee.com).

Direct injection adds about 10–12% extra water flow (from condensed steam), eliminates reboiler tube fouling, and simplifies the flowsheet (pdfcoffee.com). Recent SWS columns often have 35–45 real trays with overall vapor–liquid separation efficiency of 25–45% per tray (digitalrefining.com). Simulation shows that increasing trays (e.g., 18 to 32) can cut steam by ~20% (pdfcoffee.com), though real tray efficiencies remain modest.

pH strategy and dosing control

pH control shapes which contaminant strips best. Ideally, a two‑stage system uses a low‑pH column (<5) to liberate H₂S (limiting HS⁻ formation) and a high‑pH column (>10) to strip NH₃ (limiting NH₄⁺ formation) (yokogawa.com). In practice, most refineries run a single stripper at pH ~7–9 (often ~8) as a workable compromise (yokogawa.com). Caustic or CO₂ trims are metered with dosing pumps to hit setpoint in the feed or bottoms.

Steam injection is typically counter‑flow with internal reflux (a top‑tray pump‑around) rather than an external reflux loop, which further simplifies the design (digitalrefining.com).

Bottoms quality and reuse options

Well‑designed strippers deliver bottoms with ≤1 ppm H₂S and ≤10 ppm NH₃ targets (bcinsight.crugroup.com). In field practice, NH₃ is tougher to strip than H₂S, so operators often accept ~30–80 ppmw NH₃ versus essentially nil H₂S (digitalrefining.com). Bottoms are cooled via feed/effluent exchange and coolers before routing off‑plot.

Non‑phenolic stripped water is often reused as process water. A common path is once‑through crude desalter wash, with some sites eliminating the old wash tower and using warm SWS bottoms directly in crude units (digitalrefining.com; bcinsight.crugroup.com). Hydrotreater trains also reuse their own stripped wash water.

The economics are real: one refinery blended ~33% SWS reuse (15% to a hydrocracker wash, 18% to crude desalter wash) with no operational upsets, saving roughly $1 million in one year of boiler‑feed water costs (watertechonline.com). At Saudi Aramco’s Ras Tanura, providing 50% stripped sour water in crude wash yielded stable water quality and large cost savings; monitoring indicated the SSW performed as well as 100% fresh makeup under the site’s conditions (watertechonline.com; watertechonline.com).

Segregation of phenolic streams

Only non‑phenolic sour water is typically recycled. Phenolic sour water (from coker/FCC) carries dissolved organics — phenols, cyanides, heavy oils — even after stripping, which harm catalysts and upset boilers, so it is sent to full effluent treatment (bcinsight.crugroup.com). Grassroots designs often install separate SWS trains for phenolic vs. non‑phenolic streams, with only the non‑phenolic bottoms recycled (bcinsight.crugroup.com).

Polishing before reuse or discharge

Even after stripping, bottoms can carry tens of mg/L NH₃ (largely as NH₄⁺ at pH ~8) and non‑volatile impurities. For wastewater plants, refineries rely on nitrifying biology; many use activated sludge systems to oxidize NH₄⁺ to nitrate. Some sites add pre‑aeration or an air‑strip column to degas NH₃ before the bioreactors.

Traces of oil/hydrocarbons are removed ahead of the SWS or in polishing so the WWTP receives minimal free oil (pall.com). A compact flotation stage such as a dissolved air flotation unit is common to remove suspended solids and oils before blending with other effluents.

Refractory organics can remain significant. Analyses of stripped sour water report dissolved organic carbon on the order of 500–1000 mg/L and a low BOD/COD ratio (~0.27), indicating poor biodegradability (scielo.br). Advanced oxidation processes such as UV/H₂O₂ (hydrogen peroxide activated by ultraviolet light) have removed 90–95% of DOC in tests (scielo.br). Pairing AOPs with modest pretreatment — for example, reducing turbidity with a sand and silica filter — enabled use as cooling‑tower makeup in one case (scielo.br). UV reactors such as ultraviolet systems provide the irradiation stage for UV/H₂O₂ trains.

Before biological treatment, pH is typically adjusted from 8–10 toward neutral (using CO₂ or acid) to optimize nitrification. Many refineries meter these trims with chemical dosing pumps.

Standards and plant integration

Local limits drive final polishing. Indonesian petrochemical standards (PermenLH) commonly set sulfide (H₂S) near ~1.0 mg/L and ammonia–N at ~5–10 mg/L (pengolahanlimbah.com). SWS units are designed so their effluent comfortably meets H₂S <0.1–1 mg/L and NH₃ ~5–10 mg/L (digitalrefining.com; bcinsight.crugroup.com). Residual contaminants (e.g., traces of phenol or oil) are then handled in the main wastewater plant via air stripping, biological oxidation, and final polishing (bcinsight.crugroup.com; scielo.br).

Performance, steam economy, and payback

Simplified SWS designs — direct steam, no external reflux, robust trays — are now common (pdfcoffee.com; pdfcoffee.com). Done well, a unit uses on the order of 0.15–0.20 kg steam per liter of sour water (~16% by weight), targets <1 ppm H₂S and ~10 ppm NH₃, and sets up significant reuse and cost savings (digitalrefining.com). Efficient stripping also avoids upsets — from overloaded SRU incinerators to stressed wastewater plants — while enabling reuse programs that have delivered nearly $1 million/year in savings (watertechonline.com).