A boiler is a concentrator
Everything dissolved in the feed water stays behind when steam leaves. Run a shell boiler on raw municipal water and the hardness arrives as scale on the hottest surfaces — an insulating layer that wastes fuel long before it threatens tubes. The published numbers for shell boilers (EN 12953-10, as tabulated by boiler-water references, and BS 2486 guidance as cited by Spirax Sarco) are blunt: feed-water hardness effectively zero — below 0.01 mmol/L, about 1 mg/L as CaCO3 — feed pH around 9.2 to 9.5, dissolved oxygen below 0.02 mg/L, and boiler-water pH held at 10.5 to 12 for a typical 10 bar shell boiler. Take those as the shape of the requirement, not as your numbers: the boiler maker's own water specification governs, and where a standard is being applied it is the edition current for your plant and pressure class that counts, not the figures summarised here.
That first number is why a base-exchange softener is the minimum admission ticket for any steam boiler, not an upgrade. Softening is cheap, reliable and removes the scale-formers outright.
When softening alone stops being enough
Softening swaps calcium and magnesium for sodium — it removes hardness but not alkalinity or TDS. Published guidance (Spirax Sarco) draws the line at condensate return: with at least half the condensate coming back, softened make-up is generally adequate for a shell boiler; below roughly 40% return, or on high-TDS or high-alkalinity raw water, the make-up water starts driving excessive blowdown and carryover risk, and the options escalate — dealkalisation (weak-acid cation exchange), or reverse osmosis ahead of the softener. RO make-up dramatically cuts the dissolved load; trade references report blowdown falling to a few percent or less. Water-tube boilers at higher pressures are a different world entirely and demand demineralised water.
Alkalinity deserves its own mention because of what it becomes: bicarbonates break down in the boiler, releasing CO2 into the steam, which redissolves in the condensate as carbonic acid and quietly grooves the condensate lines. That is why condensate systems are treated (typically with neutralising amines), and why high-alkalinity make-up has costs beyond the boiler shell.
Blowdown: the running cost of TDS
Boiler-water TDS must be capped — typically around 2 000 to 3 500 ppm for shell boilers per the commonly cited BS 2486 guidance — and the cap is enforced by blowing down hot boiler water. Blowdown is the direct, continuous cost of feed-water quality: the higher the make-up TDS, the more hot water (and fuel) goes down the drain. Spirax Sarco's worked examples show automatic TDS control roughly halving blowdown against manual practice; better make-up water shrinks it further. Every rand spent on feed-water treatment is recovered in fuel not sent to the drain, and the sums are easy to run for a specific boiler.
The South African compliance frame
Water treatment is not prescribed by law — but its absence is discovered by it. Under the Pressure Equipment Regulations (OHS Act), a steam generator must be registered before use, externally inspected every 12 months, and subjected to internal inspection and witnessed hydraulic testing by an Approved Inspection Authority on a cycle not exceeding 36 months, within the SANS 347 categorisation scheme. That 36-month internal is where scale and oxygen pitting from poor feed water stop being theoretical: an AIA can and does condemn boilers. A softener, oxygen scavenging and a sensible blowdown regime are much cheaper than the conversation that follows a failed inspection.
Rule of thumb
Softener always; dealkalise or RO when condensate return is poor or the raw water is heavy; keep boiler-water chemistry inside the published bands and let automatic TDS control mind the blowdown. And treat the condensate system as part of the water plant — returned condensate is the best feed water you will ever get, provided you keep it worth returning.