Steam Turbine Blade Damage: Erosion, Cracking, Deposits and What a Borescope Can Find

Blade damage is rarely random. A steam turbine is a sequence of different environments laid end to end: hot, dry and dense at the inlet, cooler and wetter towards the exhaust, with the longest and fastest blades at the very end. Each environment has its own damage mechanisms, so where the damage sits is the first clue to what caused it, and the cause decides the fix.

That matters because the same visual finding, a rough and thinned leading edge, can mean boiler scale at one end of the machine and water at the other. Repair the blade without reading the location and the damage comes back on the same schedule.

This article works through the steam path from inlet to exhaust, covers the diaphragms that sit between the blade rows, and then turns to detection: what a borescope can and cannot see, what can be read from outside the casing, and what non-destructive testing adds once the machine is open.

Solid Particle Erosion at the Inlet

The first stages of the high pressure and intermediate pressure sections take the hardest abrasive wear. The IAPWS technical guidance on steam purity for turbine operation attributes solid particle erosion to iron oxide that grows on superheater and reheater tubes and piping, then exfoliates during transients such as start-up and shutdown. The particles scour blade surfaces mainly in the initial stages of the HP and IP turbine.

The damage shows as thinned and rounded nozzle partition trailing edges, blunted blade profiles and a roughened surface. It costs efficiency long before it threatens the blade, and its rate follows the start count rather than the running hours.

IAPWS makes a point worth absorbing: oxide growth and exfoliation are not related to steam chemistry. Better water treatment will not stop it. The remedies sit with start-up practice, bypass arrangements that keep the first flush of scale away from the turbine, and erosion-resistant coatings on the most exposed parts.

Deposits Through the Middle of the Machine

As steam expands, its ability to carry dissolved impurities falls, and each species comes out where its solubility runs out. IAPWS gives the common pattern: copper and aluminium species in the HP turbine, silica in the IP and LP. Copper only forms deposits at high steam pressures, above about 17 MPa, so many industrial machines never see it.

Deposits behave differently depending on what they are. Silica is not corrosive, but it narrows flow passages and may need mechanical cleaning once excessive. Copper roughens the blade path and costs efficiency, and IAPWS notes it can be removed by foam chemical cleaning. Sodium salts, chlorides and sulphates are the dangerous ones, because they are corrosive and they absorb moisture when the machine stands.

The mechanical consequence is also real. Deposits reduce the swallowing capacity of the turbine and change the pressure distribution between stages, which loads the thrust bearing in ways the design did not intend. Our guide to common steam turbine failures covers how deposits link to the wider failure picture.

Cracking in the Phase Transition Zone

Further down the LP turbine, the steam starts to condense. IAPWS calls this the phase transition zone and names the three most important corrosion-related failure mechanisms in any LP turbine: pitting, corrosion fatigue and stress corrosion cracking.

The sequence matters for prevention. Impurities concentrate in the first liquid films that form on blades and discs. During an unprotected shutdown, deposits on those surfaces absorb moist air and pits form. After the restart, running stresses grow cracks from the pits. IAPWS also notes that hot sodium hydroxide films can cause stress corrosion cracking even without oxygen. Cracks favour blade roots, disc rim attachments, and shroud and tenon connections, which are exactly the places a visual inspection sees worst.

The fix lies outside the blade: steam purity in service and dry air at standstill. Our guide to steam turbine preservation and lay-up covers the standstill half.

High-Cycle Fatigue and Foreign Objects

High-cycle fatigue is cracking driven by frequent stress reversals, such as blade vibration. It becomes a problem when a blade row's natural frequency sits close to an excitation frequency, and a well-designed row usually gets there because something changed: a repair blade with different mass, lost damping from a broken lacing wire or shroud, deposits that shift the frequency, or long running at an off-design speed on a mechanical drive machine. Cracks start at roots, tenons and lacing wire holes.

Foreign object damage shows as nicks, dents and torn leading edges, usually on the first stages downstream of where the object entered. Weld debris and loose parts after pipework repairs are common sources, as are fragments from the machine's own upstream stages. Every dent is also a stress raiser, which is how foreign object damage becomes fatigue damage later. The finding that matters is the source, not the dent.

Water Droplet Erosion at the Last Stages

The last LP stages of a condensing machine run in wet steam. IAPWS describes how liquid films on the blades break up into droplets up to 100 micrometres across, far larger than the fine condensate, and how these larger droplets erode blades in the downstream stages.

The classic pattern is leading edge erosion on the last stage blades towards the tip, where blade speed is highest. Manufacturers protect that edge with shields or hardened material, and the inspection question is whether erosion is still inside the shielded zone. A second pattern, trailing edge erosion near the blade root, is commonly associated with long periods at low load, when flow at the exhaust recirculates. The two patterns point at different operating causes, so record which one you have.

Where blade damage appears in the steam path, and what usually causes it there. The location is the first clue to the mechanism. Source: MIMAH engineering practice, after IAPWS TGD5-13.

Diaphragm Damage

Diaphragms carry the stationary nozzle partitions between rotating rows and hold the full stage pressure drop. They are often treated as secondary to the blades, and they should not be, because a damaged diaphragm changes the flow into every row downstream.

Partition erosion. Solid particles in the HP stages and water in the LP stages erode partition trailing edges, which changes throat area and exit angle and costs stage efficiency.

Dishing and distortion. The pressure difference pushes the diaphragm downstream, and in hot stages creep adds to it over years. The result is lost axial clearance and, eventually, a rub against the rotating row.

Cracking. Partitions crack at their welds to the inner and outer bands, and cracked pieces can break free and enter the blade path.

Seal and joint damage. Worn packing, deposit-clogged throats and horizontal joint distortion complete the list.

Distortion is found by measurement against the manufacturer's limits, not by eye.

What a Borescope Can and Cannot See

Borescope inspection puts a camera probe through inspection ports and other openings to view the steam path without lifting the casing. For the stages it can reach, it is the best early warning available short of an outage.

What it finds. Leading and trailing edge erosion, deposit presence and extent, foreign object damage, missing shroud or blade pieces, rub marks, and cracks large enough to be visible on the surfaces the probe can reach. Diaphragm partition trailing edges near a port are usually visible too.

What it misses. Stages with no access. Blade roots inside their attachments. Tight cracks and anything below the surface. Clearances. Deposit chemistry, which needs a sample. Measuring scopes can size some features, but coverage is still limited to what the tip can reach.

A clean borescope result therefore means the visible surfaces are clean. It does not clear the roots, and it says nothing about the phase transition zone cracking described above. Our turbine inspection checklist covers where a borescope fits among the inspection levels.

Reading Damage From Outside the Casing

Stage pressure surveys. Record stage and extraction pressures and temperatures at a repeatable load and steam condition, and compare them with design and with your own baseline. IAPWS notes that pressure changes from flow path plugging are usually detected by monitoring turbine pressures. Deposits narrow flow area and raise pressure upstream of the fouled stage; erosion that opens the flow area moves it the other way. A structured power plant energy audit turns these readings into section efficiencies.

Vibration trends. A sudden step in once-per-revolution amplitude or phase suggests mass has left the rotor, and a released shroud segment or blade piece fits that signature. A slow drift is more consistent with uneven deposits or a developing rub.

Thrust behaviour. Rising thrust bearing temperature or axial position shift at the same load points at a change in stage pressures, often from deposits.

What each detection method finds and what it misses. None of them alone clears a steam path. Source: MIMAH engineering practice.

Non-Destructive Testing During an Outage

With the machine open and the blades cleaned by a method approved for the material, visual inspection comes first, then the method suited to the location. The ASNT overview of NDT methods describes each.

Magnetic particle testing finds surface and near-surface cracks in ferromagnetic materials, which covers many blade and disc steels.

Liquid penetrant testing finds surface-breaking cracks in non-porous materials, including non-magnetic ones such as erosion shield alloys.

Ultrasonic testing finds subsurface flaws and is the usual route into blade roots and attachments that cannot be seen.

Eddy current testing finds surface cracks in conductive materials quickly, which suits scanning many blades.

The method should be named in the inspection plan, with the acceptance criteria, before the casing comes off.

Repair Options

Blend and dress. Small nicks and shallow cracks are ground out to a smooth profile within the manufacturer's material removal limits, then re-tested to prove the indication has gone.

Weld repair. Eroded leading edges, tenons and diaphragm partitions can be rebuilt under a qualified welding procedure with the right heat treatment. Done badly, the weld becomes the next crack initiation site.

Re-blading. Replacing a row means new blades weighed and arranged around the disc, the rotor rebalanced, and row frequencies checked where the design requires it.

Replacement. When a disc is cracked or a diaphragm is beyond repair, replacement is the route. Where the original manufacturer no longer supports the machine, reverse engineering of the part is often faster.

Every one of these restores the part. None of them removes the cause, which is why a repair plan without a cause is a plan for the next outage. Our steam turbine repair guide covers how to scope the work.

The repair routes for blade and diaphragm damage, from least to most invasive. Each restores the part; none removes the cause. Source: MIMAH engineering practice.

The Cause Usually Sits Outside the Blade

Most of the damage above is decided upstream of the blade row: boiler oxide on starts, steam chemistry in service, and air and moisture at standstill. IAPWS sets out steam purity limits for exactly this reason, and a plant that tracks them, lays up properly and keeps a stage pressure baseline finds blade damage early and cheaply.

MIMAH's rotating equipment team inspects and repairs steam paths, including reverse engineering of blades and other critical spares where support has lapsed, and has rehabilitated 14 MW steam turbines in Nigeria. If you have borescope findings, a pressure trend you cannot explain, or a blade repair quotation to review, get in touch.