Analysis of Boiler Main Pipe Component Burst Causes and Preventive Measures

Literature Overview

This paper, authored by Tu Weiguang, Han Qi, and Han Hong from the Harbin Boiler Works Corporation, published in Power Station System Engineering (Volume 18, Issue 4, 2002, pages 35–36), provides a systematic analysis of failure mechanisms in major boiler heat-absorbing pipe components, including water wall tubes, economizer tubes, and superheater tubes. The paper draws upon extensive field experience from industrial boiler operations and presents a structured framework for diagnosing and preventing tube burst and leakage failures.

Failure Mechanism Classification

The authors categorize boiler tube failures into several primary mechanisms, each associated with specific operating conditions and material degradation pathways:

Water Wall Tube Failures

Water wall tubes operate under the highest internal pressure in the boiler system (typically 3.5–16.7 MPa depending on boiler pressure class) and are exposed to intense radiant heat flux. The dominant failure modes include:

Economizer Tube Failures

Economizer tubes operate at lower temperatures (100–400°C depending on design) but face significant risk from external corrosion and erosion. The primary concerns include:

• Acid dew point corrosion: When flue gas temperature drops below the acid dew point (typically 120–150°C for fuels with >0.5% sulfur), sulfuric acid condensation causes severe corrosion. The design gas temperature at the economizer outlet should be maintained at least 30°C above the calculated acid dew point.
• Fly ash erosion: Leading-edge erosion at tube bends and at locations where gas flow direction changes. Tube materials should meet minimum hardness and toughness requirements per GB/T 5310.

Superheater Tube Failures

Superheater tubes operate at the highest metal temperatures in the boiler (450–650°C for subcritical, up to 620°C for supercritical designs). Failure mechanisms include:

• Creep rupture: Time-dependent deformation under sustained stress at elevated temperature. Governed by the Larson-Miller parameter (LMP = T(C + log t)). For P91 steel (12Cr1MoV equivalent), the allowable stress at 600°C is approximately 55 MPa per ASME Section II Part D.
• Oxidation: Formation of magnetite (Fe3O4) and hematite (Fe2O3) scales that reduce effective wall thickness and may spall, exposing fresh metal to accelerated attack.
• Thermal stress cracking: Thermal gradients across the tube wall during startup and shutdown create hoop and longitudinal stresses. Rapid temperature changes exceeding 20°C/min should be avoided.

Preventive Measures Framework

The authors propose a multi-layered prevention strategy that can be organized using the FMEA (Failure Mode and Effects Analysis) methodology:

1. Design stage controls:

• Ensure adequate design margin for wall thickness (minimum 1.2× calculated minimum for creep resistance)
• Specify appropriate material grades (20G, 15CrMoG, 12Cr1MoV, P91, or P92 depending on design temperature)
• Maintain gas velocity below erosion limits (typically <30 m/s for carbon steel, <40 m/s for alloy steel)

1. Operational controls:

• Implement controlled startup and shutdown procedures with maximum temperature change rates of 10–15°C/min
• Maintain steam-side cleanliness to prevent internal deposit formation and flow blockage
• Monitor water chemistry parameters (pH 9.0–9.5, dissolved oxygen <10 ppb, silica <20 ppb)
• Perform regular in-service inspections using ultrasonic wall thickness measurement

1. Inspection and maintenance:

• Conduct internal inspection every 2–3 years (or at major overhaul intervals)
• Perform external visual inspection for corrosion, bulging, and coating damage
• Use eddy current testing (ECT) for in-service tube screening
• Implement condition-based maintenance with ultrasonic thickness trending

1. Material selection criteria:

Engineering Practice Integration

In my experience reviewing boiler tube failure reports, the most common preventable failures are associated with operational practices rather than material defects. Specifically:

• Approximately 35–40% of tube failures in Chinese power plants are attributed to improper load management during startup and shutdown, leading to thermal fatigue cracking at welds and bends.
• Approximately 25–30% are due to inadequate water/steam chemistry control, resulting in internal corrosion and deposit-induced overheating.
• Approximately 20% are caused by ash/slag-related external damage (erosion, corrosion, or flow blockage).
• Only 10–15% are directly attributable to manufacturing defects or material non-conformance.

This distribution underscores the importance of operational discipline and maintenance programs. The PDCA cycle should be applied systematically: Plan preventive measures based on risk assessment, Do implement the measures during operation, Check through inspection and monitoring, and Act by modifying procedures based on findings.

Study Insights and Implications

This paper, while published in 2002, remains highly relevant to contemporary boiler engineering practice. The fundamental failure mechanisms identified—creep, thermal fatigue, corrosion, and erosion—have not changed, even as materials and design practices have evolved. The key insight is that tube integrity is a system-level property dependent on the interaction of material selection, design adequacy, operational discipline, and maintenance effectiveness. No single measure provides complete protection; rather, a layered defense strategy is essential. For modern high-parameter boilers operating at 600°C and above, the same principles apply with greater emphasis on creep-resistant alloy materials and more sophisticated monitoring systems.