Marine Boilers and Steam Systems

Marine boilers are class-surveyed pressure vessels. Every main boiler and auxiliary boiler aboard a vessel classed with a major society must satisfy the society’s pressure-vessel rules, IACS Unified Requirements M, and SOLAS Chapter II-1 Regulations 26 through 34. This article covers the two principal boiler types, their regulatory framework, the boiler mountings that class rules mandate, the feedwater and water-treatment system, exhaust-gas economizers and their soot-fire hazard, the safety-valve accumulation test, class survey intervals, and MARPOL Annex VI requirements that apply to boiler combustion. For any numerical work, ShipCalculators.com hosts the boiler efficiency direct method calculator, the boiler blowdown check calculator, the safety valve area (ASME I) calculator, and the exhaust-gas boiler fouling check calculator.

Background and classification

Role of steam aboard ship

Steam serves six distinct functions on a typical cargo ship. Main propulsion on steam-turbine vessels (LNG carriers of the steam-plant generation and dedicated naval auxiliaries) is the most energy-intensive, consuming 70 to 80 tonnes per hour of steam on an LNG carrier with twin-boiler, single-turbine plant running at approximately 60 bar gauge / 510 degrees Celsius. Cargo heating on tankers is next in scale: crude oil with a 30-degree-Celsius pour point needs to be kept above that temperature throughout a multi-week passage, and asphalt carriers require coil temperatures approaching 200 degrees Celsius. Fuel oil heating is non-negotiable on any ship burning heavy fuel oil (HFO), because HFO must reach 120 to 150 degrees Celsius before injection to achieve the 12 to 15 centistokes viscosity that atomizing nozzles require. Accommodation heating, fresh-water generation, and miscellaneous services (lubricating oil purifiers, fuel purifiers, galley, laundry) each draw smaller but continuous steam flows.

On motor ships, all of these except main propulsion are covered by auxiliary boilers of relatively modest capacity. The marine diesel engine displaces the main boiler; the exhaust-gas economizer captures waste heat from the engine exhaust to supplement the oil-fired auxiliary.

Fire-tube (smoke-tube) boilers

In a fire-tube boiler, combustion gases pass through a set of tubes, each typically 50 to 75 mm in diameter, that are surrounded by the water body. The Scotch marine boiler, still widely fitted as an auxiliary on cargo ships, consists of a cylindrical shell with one or two corrugated furnace flues (combustion chambers) and two to four passes of fire tubes. Combustion takes place in the furnace; the hot gas reverses and passes through the fire tubes toward the front, then turns again through a second tube bundle toward the rear stack.

The design inherently contains a large volume of water relative to steam output, which has two consequences. First, load response is slow: pressure takes longer to rise or fall than in a water-tube unit. Second, the design is tolerant of moderate feedwater contamination, because a brief excursion in dissolved solids or hardness doesn’t immediately scale a small tube surface. Typical auxiliary fire-tube boilers for cargo ships run at 7 to 16 bar gauge, producing 1 to 10 tonnes of steam per hour. The Norwegian manufacturer Aalborg Industries (now Alfa Laval) offers the Aalborg AQ-type (renamed to Mission range) as a standard Scotch marine auxiliary; Mitsubishi and Volcano (Sumitomo Heavy Industries) supply comparable units in the Japanese market.

Water-tube boilers

In a water-tube boiler, water circulates inside a set of tubes, each typically 38 to 76 mm outside diameter, heated externally by combustion gases. Feedwater enters a lower header or mud drum, rises through the generating tubes as a steam-water mixture under heat, and separates in the upper steam drum. The design supports much higher pressures than a fire-tube unit because the individual tube wall thickness only needs to contain the pressure acting on a small-diameter tube, rather than the full boiler pressure acting on a large-diameter shell.

Main propulsion boilers on LNG carriers of the Moss and membrane tank steam-plant generation operate at 60 to 70 bar gauge with steam temperatures of 490 to 515 degrees Celsius. The Mitsubishi Ultra-High Efficiency Boiler (UEHB) type, fitted on several large LNG carriers, achieves thermal efficiencies above 92 percent at design load. Exhaust-gas economizers are also water-tube units, although at atmospheric-pressure steam output (typically 4 to 8 bar gauge) and much smaller evaporation rates.

Water-tube designs are more sensitive to feedwater quality. Scale just 0.8 mm thick on the inside of a 38 mm tube reduces heat transfer by roughly 40 percent and raises tube-metal temperature toward the design limit. Class rules for water-tube boilers consistently specify tighter feedwater limits than for fire-tube units of the same pressure.

Boiler type comparison

Regulatory framework

SOLAS Chapter II-1: mandatory requirements

SOLAS Chapter II-1 is the baseline international instrument for boiler safety. Regulation 26 (Machinery) establishes the general obligation that all machinery must be designed, constructed, installed, and maintained to ensure safety. Regulations 30, 32, 33, and 34 carry the specific boiler provisions.

Regulation 30 governs steam-pipe systems. It requires that every steam pipe and fitting through which steam may pass be designed and constructed to withstand the maximum working stress likely to be experienced in service, that the pipe be protected against the risk of scalding, and that the system include adequate provision for drainage and the prevention of water hammer.

Regulation 32 covers boiler feed systems. For every boiler, there shall be at least two separate means of feeding, each capable alone of maintaining the normal water level. On large main propulsion boilers, this typically means two independent motor-driven feed pumps with separate suctions and a separate turbine-driven feed pump as backup.

Regulation 33 is the safety-valve regulation. Every steam boiler shall be fitted with not fewer than two safety valves of adequate capacity. The combined discharging capacity of all the safety valves fitted to a boiler shall be such that, with the stop valves closed and all heat input at the maximum rate, the pressure cannot rise more than 10 percent above the maximum allowable working pressure (MAWP). That 10 percent figure is what the accumulation test verifies. Administrations and class societies regularly accept the ASME BPVC Section I overpressure allowance of 6 percent for the first valve and 10 percent for the maximum combined relief, because ASME I (Power Boilers) is a recognized standard under SOLAS 1974 Regulation II-1/46.

Regulation 34 covers main and auxiliary steam-pipe connections, requiring that every boiler be fitted with a main steam stop valve and, where two or more boilers are connected to a common steam main, an auxiliary steam stop valve to allow each boiler to be isolated independently.

IACS Unified Requirements M5

IACS UR M5 (Boilers, Thermal Oil Heaters and Unfired Pressure Vessels) sets the class-society-independent standard that all IACS member societies are bound to enforce. The current edition is the 2022 revision. Key provisions:

UR M5.1 defines scope: it applies to steam boilers with a design pressure above 0.5 bar and a volume above 25 liters, exhaust-gas boilers, unfired steam generators, and thermal-oil heaters. Smoke-tube boilers for domestic services with design pressure not exceeding 10 bar are treated under relaxed provisions, but the main auxiliary boilers on cargo ships fall well within the full scope.

UR M5.2 sets the survey intervals. Internal examination at not more than 30 months. Hydraulic pressure test at each class renewal survey (every 5 years under continuous class) at 1.25 times the MAWP, or as the society’s rules specify but not less than 1.1 times MAWP for a re-test. UR M5.2 also mandates an accumulation test after each major overhaul that involves the safety valves or the boiler drum.

UR M5.3 addresses materials. All pressure parts must be made from recognized pressure-vessel-quality materials traceable to a recognized standard (ASTM, EN, JIS, or GOST). The classification survey of materials at the mill applies; class surveyors witness tensile and impact tests for boiler drums, and radiographic or ultrasonic examination of welds is mandatory for longitudinal shell seams.

UR M5.4 covers mountings. Each boiler must have: at least two independent water-level indicators (gauge glasses), each with a self-closing test cock and a ballvalve or equivalent isolation; the two safety valves required by SOLAS 33; a main stop valve; a feed check valve (non-return) on each feed line; a blowdown valve at the boiler bottom; a pressure gauge; and a high-pressure alarm/cutout and a low-water alarm/cutout. The level indicators must be positioned so that the engineer can read both from the normal working position.

Classification society boiler rules

DNV Rules for Classification: Ships, Part 4 Chapter 7 (Pressure Vessels, Boilers, Thermal Oil Heaters and Other Pressure Equipment) closely follows UR M5 but adds prescriptive design equations. The design pressure for shell boilers is defined as $p = \frac{2 \cdot \sigma_{all} \cdot e}{\left(D_{o} - e\right)}$ where $\sigma_{all}$ is the allowable material stress at design temperature, $e$ is the shell thickness, and $D_{o}$ is the outside shell diameter. DNV requires NDT of all Category I welds (longitudinal shell seams, drum-to-end plate welds, nozzle-to-drum welds) and documentation in a design appraisal certificate from DNV.

Lloyd’s Register Part 5 Chapter 6 (Boilers, Pressure Vessels, Pipe Systems and Their Associated Machinery) includes the LR Type Approval scheme for boilers. An LR-type-approved boiler from a recognized manufacturer (Alfa Laval Aalborg, Mitsubishi, Volcano) can be fitted on any LR-classed vessel under survey by reference to the type certificate, avoiding the need to submit full calculations per vessel. Renewal survey at 5 years includes internal examination and hydraulic test to 1.25 times the MAWP.

ABS Rules for Steel Vessels Part 4 Chapter 4 follows ASME BPVC Section I for boilers destined for vessels in US trades, accepting ASME National Board stamps as evidence of fabrication survey. For vessels on non-US trades under ABS class, ABS can accept alternative recognized standards provided they meet the intent of ASME I.

ClassNK (Nippon Kaiji Kyokai) Part D Chapter 6 governs boilers and pressure vessels. ClassNK’s rules align with IACS UR M5 and additionally reference JIS B 8201 (Shell Boilers) and JIS B 8270 (Pressure Vessels). A significant proportion of Japanese-built LNG carrier main boilers are ClassNK-certified.

Boiler mountings and safety devices

Safety valves: setting and the accumulation test

The safety valve is the last line of defense against boiler over-pressure. SOLAS II-1 Regulation 33 and IACS UR M5.4 require a minimum of two valves on every boiler. Most class societies require that, if two valves are mounted on a single valve chest, they still count as two independent safety functions provided each valve has its own seating.

Setting: one valve is set at or below the MAWP; the second valve may be set up to 3 percent above. A spring-loaded, direct-acting safety valve set at the MAWP will begin to lift when steam pressure reaches that point. Full lift occurs at 3 percent above set pressure under ASME I, or 10 percent above MAWP for combined discharge capacity verification per SOLAS 33.

The accumulation test procedure: the boiler is brought to operating pressure, all steam-consuming services are isolated (blow-off valve closed), and the burner is fired at maximum firing rate. A clock is started when pressure passes the MAWP. The test passes if the pressure stabilizes at or below 1.10 times MAWP with the safety valve(s) discharging. The test is documented in the class survey record. IACS UR M5 requires this at each renewal survey and after any repair to the safety valves or pressure drum. DNV Part 4 Ch.7 Sec.8 and LR Part 5 Ch.6 both mandate the test identically.

Capacity calculation: the safety valve area (ASME I) calculator computes the minimum required orifice area from steam output capacity, set pressure, and saturated or superheated steam conditions. The ASME I formula for saturated steam is:

where $A$ is the minimum required orifice area (in²), $W$ is the required relieving capacity (lb/h), $K_{d}$ is the effective discharge coefficient (0.975 for safety valves with certification), $P_{1}$ is the set pressure plus atmospheric pressure (psia), $K_{b}$ is the capacity correction factor for back pressure, $K_{n}$ is the Napier correction for steam pressures between 1,515 and 3,215 psia, and $K_{sh}$ is the superheat correction factor (1.0 for saturated steam). For typical auxiliary boiler pressures in the 7 to 20 bar range the correction factors $K_{n}$ and $K_{sh}$ are both 1.0 unless the steam is superheated.

Water-level indicators

Class rules are specific about water-level gauges. IACS UR M5.4 requires at least two independent gauge glasses per boiler. Each gauge glass must connect directly to the boiler shell or drum by short, unrestricted connections; no shared cross-connection between the two glasses is permissible because a single blockage would then disable both. Each must have an isolation cock so the glass can be shut off and the gauge removed safely while the boiler is under pressure. Self-closing test cocks allow the water and steam spaces to be separately tested.

On fire-tube boilers, the gauge glass centerline must be at least 50 mm above the top of the highest heating surface (the fire-tube crowns), ensuring a visible water level before the tubes are exposed. On water-tube boilers, the normal working water level (NWL) in the drum must be clearly marked, and the gauge glass range must span from at least 50 mm below the low-water alarm point to at least 50 mm above the high-level alarm point.

IMO MSC/Circ.834 (Guidelines for Assessing the Adequacy of Alarm Systems) includes boiler water-level in the list of critical alarms that must activate in the engine-control room and at the local station simultaneously.

Feed check valves and the non-return requirement

SOLAS II-1 Regulation 32 and IACS UR M5.4 together require a feed check valve (a non-return valve, often combined with a screw-down stop function) on every feedwater supply line entering the boiler. The purpose is twofold: it prevents backflow of boiler water into the feed system if feedwater pump pressure falls below boiler pressure, and it isolates the boiler if a feed line ruptures. On two-feed-pump installations, each pump has its own feed check valve; both check valves back up to a common feedwater distribution pipe but they must be independently closeable.

Blowdown valves

Bottom blowdown removes sludge that settles at the lowest point of the boiler shell or mud drum. Class rules require a dedicated bottom blowdown valve (not the drain valve) of the quick-opening type, with a secondary isolation valve directly at the boiler that is opened first. Blowdown to the ship’s side is only permissible into a blowdown silencer/cooler; most ships direct blowdown to a blowdown cooler before overboard discharge or to the cascade tank. Surface blowdown (continuous or manual) removes dissolved-solids-rich water from the water surface near the steam-water interface to control TDS.

The boiler blowdown check calculator computes the required blowdown rate as a function of feedwater TDS, target boiler water TDS, and steam output. The governing equation is the cycles-of-concentration ratio:

where $BD\%$ is blowdown as a percentage of steam production, $TDS_{fw}$ is feedwater TDS in mg/L, and $TDS_{bw}$ is the target boiler water TDS in mg/L. For a typical auxiliary boiler running at 2,000 mg/L boiler water TDS against 50 mg/L feedwater TDS, the blowdown rate works out to approximately 2.6 percent of steam output.

Main and auxiliary steam stop valves

The main steam stop valve isolates the boiler from the steam main. SOLAS II-1 Regulation 34 requires this valve on every boiler. On a twin-boiler installation feeding a single steam main (as on an LNG carrier with two boilers and one main turbine), an auxiliary stop valve between each boiler and the main stop valve allows one boiler to be taken off line for maintenance without interrupting propulsion.

Class rules require that main and auxiliary stop valves be of the screw-down, non-return type or the equivalent, capable of being closed against full boiler pressure. The valve seat must not allow leakage past the disc when closed. Annual class survey verifies seat tightness and stem packing integrity.

Feedwater system and water treatment

The hotwell and cascade tank

Returned condensate collects in the hotwell, which is typically a tank in the double bottom or low in the machinery space. On an LNG carrier, the hotwell receives condensate returns from the main turbine condenser, auxiliary steam users, and the drain coolers, all at temperatures ranging from 60 to 90 degrees Celsius. Make-up fresh water (from the ship’s evaporators or shore supply) is added to compensate for steam losses, primarily the steam consumed in cargo tank heating coils, which doesn’t condense and return.

The cascade tank (also called the observation tank or inspection tank on some vessels) is placed in the condensate return line before the hotwell. Its purpose is to allow the engineer to inspect the condensate for oil contamination from a steam-heated fuel-oil heater or from a leaking steam heating coil. If a heating coil in a fuel oil service tank cracks, fuel oil contaminates the condensate. The cascade tank gives a visible observation point and allows diversion of contaminated condensate overboard through the bilge system rather than forward into the boiler, which would cause catastrophic tube fouling.

Deaeration

Dissolved oxygen causes corrosion of boiler internals, particularly in the water-drum, mud-drum, and lower-header region of a water-tube boiler where temperature is highest. The deaerator removes dissolved oxygen by heating the feedwater to near-saturation temperature, which reduces the solubility of oxygen to near-zero. A spray deaerator operates at atmospheric pressure, heating feedwater to approximately 105 degrees Celsius; a pressurized deaerator operates at 1 to 2 bar absolute, heating to 120 degrees Celsius, for higher-pressure boiler applications.

After deaeration, the target dissolved oxygen content is below 0.02 mg/L (20 ppb) for high-pressure water-tube boilers, per most class society boiler water chemistry guidelines. For lower-pressure auxiliary boilers (below 20 bar), some guidelines accept up to 0.05 mg/L dissolved oxygen, compensated by chemical oxygen scavenging.

Chemical treatment

Boiler water chemical treatment has four objectives: scale prevention, corrosion prevention, pH control, and sludge conditioning for blowdown removal.

Scale prevention uses phosphate treatment or the polymer-only approach. The coordinated phosphate-pH program (applicable to boilers above 20 bar) maintains phosphate in the range 2 to 10 mg/L as PO₄ with a corresponding pH of 9.0 to 9.6. At these conditions, any hardness that bypasses the feedwater softening precipitates as a soft calcium-phosphate sludge rather than the hard calcium-carbonate or calcium-sulfate scale that binds to tube surfaces. For lower-pressure auxiliary boilers, the all-volatile treatment (AVT) or the polymer program is common: a dispersant polymer keeps any residual hardness in suspension, from which it’s removed by bottom blowdown.

Corrosion prevention targets two mechanisms. Oxygen pitting is addressed first by the deaerator and then by an oxygen scavenger. Sodium sulfite (Na₂SO₃) is the standard scavenger for boilers below 60 bar; it reacts with dissolved oxygen at a ratio of approximately 8 mg Na₂SO₃ per mg O₂. Hydrazine (N₂H₄) was used for high-pressure main propulsion boilers but is now restricted or banned on most vessels for toxicity and carcinogenic reasons; MOCA (methylbenzotriazole and similar products) or catalyzed sodium sulfite are the replacements. Condensate system corrosion (from dissolved CO₂ and residual oxygen) is treated with neutralizing amines, typically cyclohexylamine or morpholine, added to the hotwell to raise condensate pH to 8.5 to 9.0.

Caustic embrittlement is an older failure mode in riveted boilers, irrelevant to modern welded construction, but free caustic (NaOH) above 20 mg/L in boiler water can still cause stress-corrosion cracking at welds in high-pressure units. Coordinated phosphate treatment keeps free caustic below this threshold.

Water quality testing and records

IACS UR M5 and all class society boiler rules require that boiler water be tested at regular intervals, with results recorded in the ship’s log or a dedicated boiler water log book. The minimum test frequency is daily for ships in service; the parameters tested are pH, TDS or conductivity, chloride content, phosphate or polymer residual, and oxygen scavenger residual. Hardness is tested on feedwater, not boiler water, because properly operated boilers should show zero hardness in the boiler water. Silica is tested on steam-turbine ships because silica carry-over into turbine steam deposits on blades, causing balance and clearance problems.

The boiler water hardness calculator computes expected calcium and magnesium hardness precipitation and the required phosphate dose for a given feedwater hardness and boiler evaporation rate.

Combustion and burner management

Oil burner types

Marine oil burners fall into three categories based on their atomization method. Pressure-jet (mechanical) burners use fuel pressure (typically 15 to 30 bar above atmospheric) to force fuel through a small orifice that creates a fine spray. They are simple and common on auxiliary boilers; their limitation is a narrow turndown ratio (about 3:1), meaning they can’t fire at much less than one-third of maximum capacity without producing poor combustion. Steam-atomizing burners use a small flow of steam at 2 to 5 bar gauge to mechanically break up the fuel oil; they achieve wider turndown (up to 10:1) and are preferred for main propulsion boilers and large tanker auxiliaries. Rotary-cup burners spin a rotating cup that flings fuel into a fine film; they were common in older main propulsion plants but are less prevalent in modern installations.

All three types require the fuel oil to arrive at the burner at correct viscosity (12 to 15 centistokes for HFO). The viscosity controller in the fuel oil service system adjusts steam heating to reach this target before the fuel reaches the nozzle. The system fuel heater steam heat exchanger calculator addresses the fuel preheater steam duty.

Combustion control

A fully automatic burner management system (BMS) controls the firing sequence and modulates heat output. The standard sequence for a cold start is: pre-purge (forced-draught fan runs for at least five air changes of the furnace volume before ignition, to clear any unburned fuel), pilot ignition (spark ignites a small pilot flame), main fuel valve opens and the main flame is proven by the UV or IR flame detector, and then the modulating control takes over to match heat output to steam demand.

The Combustion Management System (CMS) on modern boilers uses a combustion analyzer measuring O₂ and CO in the flue gas to trim the air-fuel ratio. The optimum excess air is typically 10 to 20 percent (O₂ of 1 to 3 percent in the flue gas at the economizer inlet), balancing incomplete combustion (too little air, CO rises) against stack losses (too much air, flue gas temperature rises).

Flame failure shuts the fuel supply within 1 to 4 seconds of losing the flame signal. This requirement comes from class society rules on boiler control systems (DNV Part 4 Ch.7 Sec.6, LR Part 5 Ch.6 Sec.7). After a flame failure trip, a manual reset is required; the system cannot auto-relight without operator intervention.

MARPOL Annex VI: boiler combustion emissions

MARPOL Annex VI Regulation 14 imposes the global 0.50% m/m sulfur cap on fuel, in force since 1 January 2020. Ships operating in designated Emission Control Areas (ECAs) under Regulation 14.3 must use fuel with a sulfur content not exceeding 0.10% m/m or fit an exhaust gas cleaning system (scrubber). This applies equally to boiler fuel and main engine fuel; the bunker delivery note must confirm compliance.

Regulation 13 imposes NOx limits on marine diesel engines. The Tier I, II, and III limits by regulation text apply to “each marine diesel engine,” not to boilers. Boilers are not marine diesel engines within the Annex VI definition. However, Regulation 13 also covers “auxiliary engines used as part of the main propulsion of the ship,” and a steam-turbine ship where boilers drive the main turbine sits in a gray area. In practice, IMO guidance (MEPC.1/Circ.771) and flag-state interpretation have generally treated steam-plant boilers on LNG carriers as outside the Tier III NOx scope, but jurisdictions differ.

Regulation 18 governs the bunker delivery note (BDN), requiring that the fuel supplier certify the sulfur content and that the ship retain the BDN for three years. The BDN covers all fuel, including that burned in boilers.

The broader MARPOL Annex VI framework, including CII and EEXI, affects boiler operation indirectly: boiler fuel consumption counts toward the ship’s Energy Efficiency Existing Ship Index (EEXI) and Carbon Intensity Indicator (CII). A poorly maintained or over-sized auxiliary boiler firing unnecessarily at anchor or in port worsens the ship’s CII rating under MEPC.328(76) and MEPC.364(79). The waste heat recovery credit calculator assesses the CII benefit of redirecting exhaust-gas economizer output to reduce auxiliary boiler firing.

Exhaust-gas economizers

Design and operation

The exhaust-gas economizer (EGE), also called the exhaust-gas boiler (EGB) or heat recovery steam generator (HRSG), extracts heat from the main engine’s exhaust gas. A two-stroke main diesel engine running at maximum continuous rating (MCR) exhausts gas at approximately 300 to 380 degrees Celsius, depending on engine design and the presence of turbocharger exhaust bypass. The EGE is a water-tube bundle inserted in the exhaust uptake, with tubes carrying water or steam at 4 to 8 bar gauge. At full main-engine load, a large slow-speed engine of 30,000 to 40,000 kW can sustain an EGE output of 3 to 6 tonnes per hour of steam, enough to meet most of the ship’s auxiliary steam demand underway.

Most modern motor ships run a composite arrangement: the EGE generates steam into a common steam drum or header, from which the oil-fired auxiliary boiler also delivers. The oil-fired boiler fires only when the EGE output falls short, typically at maneuvering, in port, or at low engine load. This keeps auxiliary boiler fuel consumption at effectively zero during long ocean passages.

Soot fires

The soot fire is the most serious hazard associated with exhaust-gas economizers. Combustion in the main engine is never perfectly complete across all operating modes; during low-load operation, starting, or maneuvering with poor fuel atomization, unburned hydrocarbons and soot deposit on the EGE tube surfaces. When the ship returns to full power, the hot exhaust can ignite this accumulated deposit, causing a fire in the exhaust uptake that can exceed 1,000 degrees Celsius locally.

Class rules require a steam-smothering connection, a soot blower (steam or air lances that clean the tube surfaces during operation), and a temperature alarm on the exhaust gas after the EGE (a sudden temperature rise is an early indicator of combustion in the tube bank). SOLAS II-2 Chapter 10 (Fire fighting systems) applies to any machinery space fire including uptake fires, and the fixed fire detection system in the engine room must include heat detectors in the EGE region.

Soot blowers should be operated regularly, particularly before increasing engine load after a low-load period. DNV and LR both recommend weekly soot-blower cycles as a minimum during passages. The exhaust-gas boiler fouling check calculator estimates the soot buildup rate and cleaning interval based on engine load profile and fuel sulfur content.

Steam trap management

Steam traps remove condensate from steam lines without allowing steam to pass. A failed-open trap allows steam to pass into the condensate system, wasting heat and increasing hotwell temperatures above the deaerator’s working range. A failed-closed trap causes waterlogging of steam lines, creating water-hammer risk and wet steam delivery. The steam trap failure check calculator and the system steam trap thermostatic or float calculator address trap selection and fault diagnosis.

Class survey and the survey regime

Annual class survey

The annual class survey of boilers is part of the Annual Survey of Machinery under continuous survey or the periodical survey at each anniversary. The surveyor examines:

External surfaces: insulation condition, casing for signs of corrosion or heat distortion, pipework connections, valve gland packing, instrumentation, labels, and generally accessible fittings. The surveyor verifies that safety valves are sealed and that the seal number matches the record from the last test. Alarm panel tests verify the low-water alarm, high-pressure alarm, and flame-failure trip.

Water-level indicator test: the surveyor operates the test cocks on each gauge glass to verify the water and steam connections are clear and that the visible water level corresponds to the boiler water level. Both gauges must agree within 10 mm.

Internal examination

IACS UR M5.2 requires an internal examination at intervals not exceeding 30 months. For this survey, the boiler must be cooled, depressurized, vented, and chemically cleaned or pressure-washed before the surveyor enters or inspects through manholes.

Inside the boiler, the surveyor examines tube surfaces (fire-side and water-side), welds, tube-to-tube-plate or tube-to-header joints, furnace plates (fire-tube boilers) or furnace wall tubes (water-tube boilers), supports, baffles, and any indication of overheating or corrosion. On fire-tube boilers, crown corrosion is a particular concern at the junction between the furnace flue crown and the tube plate. On water-tube boilers, the surveyors look for evidence of tube pitting on the water side, erosion on the fire side at the gas-flow reversal points, and weld deterioration at drum nozzles.

Refractory lining of the furnace and combustion chamber must be intact; cracks, spalling, or erosion that exposes the backing insulation or the pressure-part steel are defects requiring repair before return to service.

Hydraulic pressure test

The hydraulic (hydrostatic) test is conducted at every class renewal survey (every 5 years under continuous class). The boiler is filled with clean, cold water to 1.25 times the MAWP (or the value in the class rules, not less than 1.1 times MAWP for a re-test). The pressure is raised slowly, held for a minimum of 30 minutes, and then the surveyor inspects all joints, welds, connections, and fittings for leaks or deformation. No pressure drop greater than the allowable tolerance during the hold period indicates a sound structure.

Before the test, all safety valves are gagged or blanked (not set to lift at test pressure, which would be below the test pressure and would waste water and damage the valve seats). After the test, the blanks and gags are removed, the safety valves are reset and re-sealed, and the accumulation test is performed.

Special surveys and condition assessments

Boilers with a history of significant tube wastage, recurring refractory damage, or saltwater contamination of the feed system may be required by the class surveyor to undergo a focused condition survey outside the standard interval. This can include eddy-current tube testing (measuring wall thickness of individual tubes without removing them from the boiler), radiographic examination of critical welds, or metallurgical sampling of tube material. Results inform a fitness-for-service assessment; if the remaining wall thickness is below the calculated minimum required wall thickness, the tubes must be plugged or replaced.

Steam distribution and typical ship uses

Steam-turbine LNG carriers

LNG carriers of the Moss-sphere and membrane-membrane tank generations built from the 1970s through the 2000s use a twin-boiler, single-turbine or twin-turbine propulsion arrangement. Each boiler is a water-tube unit; steam is superheated to approximately 510 degrees Celsius at 60 bar gauge, supplied to the main turbine (typically a GE or Mitsubishi turbine in the 25,000 to 35,000 kW range), and exhausted to a condenser. The cargo’s natural boil-off gas at sea is piped directly to the boiler burners as a primary fuel; HFO is the backup fuel in port or when boil-off is insufficient.

Modern LNG carriers increasingly use low-speed dual-fuel diesel (ME-GI, ME-C GI, or WinGD X-DF series) or diesel-electric propulsion (DFDE), which displace the main boiler. The auxiliary steam demand remains, however, and is met by a smaller oil-fired auxiliary boiler plus an EGE on the main engines. The LNG carrier article covers propulsion system choices in detail. The steam Rankine cycle calculator and saturated steam temperature-pressure calculator are relevant for anyone working through the thermodynamic performance of steam-plant LNG carriers.

Cargo heating on tankers

Crude tankers, HFO tankers, asphalt carriers, vegetable oil carriers, and some chemical tankers carry cargoes that solidify or become unpumpable below a minimum temperature. The boiler provides saturated steam at 7 to 16 bar gauge, which circulates through coils inside the cargo tanks. The tanker cargo heating duty calculator, the cargo heating coil steam rate calculator, and the cargo steam heating time calculator handle the heat-transfer calculations for these applications.

Asphalt carriers require coil temperatures approaching 200 degrees Celsius, which demands a boiler pressure above 15 bar gauge (the saturation temperature at 16 bar gauge is approximately 201 degrees Celsius). A fire-tube boiler at 16 bar gauge, with asphalt at 180 to 195 degrees Celsius around the coils, has a small temperature driving force; the cargo heating system must be designed to account for this margin. The tanker cargo heating, asphalt calculator specifically addresses asphalt vessel steam demands.

Fuel oil and purifier heating

Heavy fuel oil enters the main engine at 120 to 150 degrees Celsius, requiring a fuel oil heater (steam-to-oil heat exchanger) in the fuel service system. The steam supply to the fuel heater is typically at 7 to 10 bar gauge saturated. The system fuel heater steam heat exchanger calculator gives the heat exchanger duty and steam consumption rate.

Centrifugal separators (purifiers) for HFO and lubricating oil run at elevated temperature for optimum separation efficiency: HFO purifiers at 95 to 98 degrees Celsius, lube oil purifiers at 80 to 95 degrees Celsius. Steam heating is provided through jacket heating of the purifier feed tank. This is a small but continuous steam load.

Turbo-generators

Steam-turbine ships often use turbo-generators in addition to or in place of diesel generators. A turbo-generator uses a small steam turbine (typically 500 to 2,000 kW) driven by main boiler steam to generate electrical power. On an LNG carrier with two propulsion boilers, a dedicated auxiliary boiler (sometimes called a “donkey boiler”) may feed the turbo-generator in port when the main boilers are offline or at low pressure.

On modern motor ships, steam-driven turbo-generators are uncommon; diesel-driven alternators are the standard. But the possibility of a turbo-generator running from the EGE during ocean passages exists on some tankers as a waste-heat electricity generation option.

Accommodation and domestic services

Steam for accommodation heating, galley, laundry, and domestic hot water is typically drawn at a reduced pressure (2 to 4 bar gauge) through a pressure-reducing valve (PRV) from the main steam supply. The PRV is a key fitting; a failed-open PRV would impose full boiler pressure on accommodation heating coils rated for 4 bar gauge. Class rules require the PRV to be fitted upstream of a safety valve set to the lower system’s design pressure.

Limitations

The information in this article draws on the 2022 edition of IACS UR M5, DNV Rules for Classification Ships Edition January 2023 Part 4 Chapter 7, Lloyd’s Register Rules 2023 Part 5 Chapter 6, ABS Rules 2024 Part 4 Chapter 4, SOLAS as consolidated through the 2020 amendments, and MARPOL Annex VI as amended by MEPC.328(76) and MEPC.364(79). Rule revisions can occur between annual updates; all regulatory figures should be verified against the current class society rules, the consolidated SOLAS text, and IACS resolutions before applying them to a specific vessel. Class society rules have minor differences in numeric values (design pressure multipliers, minimum safety valve count, hydraulic test pressure factors) even where IACS UR M5 sets the floor; the ship’s actual classification society rules take precedence.

The performance figures for boiler efficiency, steam output, and feedwater chemistry are representative of typical modern marine installations but can vary with manufacturer design, age of the boiler, fuel quality, and maintenance standard. Machinery manufacturers (Alfa Laval Aalborg, Mitsubishi, Volcano) publish operating manuals with model-specific limits; those documents override the typical values cited here.

This article covers oil-fired and exhaust-gas boilers only. Boilers fueled by natural gas, methanol, ammonia, or hydrogen involve additional hazards, modified combustion systems, and different regulatory treatments that are outside the scope of this article. The methanol as marine fuel, ammonia as marine fuel, and hydrogen as marine fuel articles cover fuel-specific considerations.

IMSBC and IMDG cargo categories, cargo compatibility, and cargo operations are outside the scope of this article.

See also

• Marine Diesel Engine
• Waste Heat Recovery System
• LNG Carrier
• LNG as Marine Fuel
• Marine Steam Turbines Overview
• Heavy Fuel Oil
• Marine Gas Oil
• MARPOL Annex VI
• MARPOL Annex VI Reg. 14: Sulphur Cap
• SOLAS Chapter II-1: Construction, Subdivision, Stability, Machinery and Electrical Installations
• SOLAS Chapter II-2: Fire Protection, Detection and Extinction
• Oil Tanker
• Methanol as Marine Fuel
• Ammonia as Marine Fuel
• Hydrogen as Marine Fuel
• Marine Auxiliary Engines and Generators

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