Monthly Archives: October 2016

Boiler Explosion!

The pictures below show what happens when a boiler catastrophically explodes.

boiler1 boiler2 boiler3 boiler4 boiler5

Why do boilers explode?

The principal causes of boiler explosions are:

  1. Boiler was built outside of USA and was not constructed as per ASME construction codes and standards
  2. Failure of the pressure parts of the steam and water sides.
  3. Malfunction of the safety and control devices
  4. Operator error
  5. Furnace gas explosion

The internationally recognized organizations National Board of Boiler Inspectors and American Society of Mechanical Engineers have developed codes and standards for the construction and operation of the boilers.

All of BPC’s inspectors have several years of experience and are certified by NBIC and local Jurisdictions for the inspections of boilers.

During these inspections, our inspectors verify the critical operating condition of the boilers and proper operation of the safety devices by visual inspection and review of records to ensure the boilers are safely operated.

Below are summarized the most important items that our inspectors verify during the inspection visits:

  1. Verify the boiler is constructed in accordance to ASME codes for the designed pressure (Maximum Allowable Working Pressure). The boiler is stamped by the manufacturer and bears the NB registration number.
  2. Verify the pressure parts of the boiler are in sound condition to withstand the maximum allowable pressure of the boiler as designed and operated. The integrity of the pressure parts could be comprised by the following causes:
  • Poor water treatment or contaminated feed water resulting in the corrosion, erosion and scale formation on the water side surfaces of the boiler.

Corrosion and erosion reduces the integrity of the pressure parts to withstand the MAWP of the boiler, resulting in leakage, cracking and rupture of pressure parts. and scale formation.

Scale reduces the heat transfer and results in localized overheating of the metal. The over-heating makes the boiler material softer and weaker and this causes distortion and makes the boiler unsafe to bear the pressure of the steam, especially in high-pressure boilers.

Scales may sometimes deposit in the valves, safety devices connection piping and condensers of the boiler and cause plugging making the devices inoperative.

Scale deposits could sometimes crack and allow direct contact of hot water with the overheated metal plate resulting in uneven metal expansion and sudden formation of a large amount of steam suddenly. This could cause localized steam explosion and damage to the boiler.

3. Malfunction of safety devices – Safety devices are tested to verify their operating parameters.

  • Safety/relief valves are tested as per NBIC/Jurisdictional mandated intervals
  • Low water control devices are tested regularly to ensure these very important controls function as desired.
  • Pressure and temperature regulators are tested to verify they operated as designed.

4. Operator training – There is a documented program for training and verification of competency of the operators.

5. Furnace explosion. This could be caused by malfunction of the burner management system, operating parameters and operator error.

  • Fuel rich mixture – Improper ratio of supplied air and fuel supply for complete combustion.
  • Improper atomization of oil – To prevent this, the oil tips must be clean, the oil temperature must be correct, the oil viscosity must be in spec, and the atomizing steam (or air) pressure and fuel oil pressure must be properly adjusted.
  • Improper purge and repeated attempts by the operator to relight the boiler. The unburnt fuel suddenly ignites after several relight attempts resulting in explosion.

Improper functioning of the burner management system – The programmable logic controllers for both the combustion control system and the burner management system should be tested at least annually to verify they are operating as designed for the application.


3 Tips for Transformer Maintenance and Testing

By BPC Chief Inspector Anzar Hasan

Power transformers are designed to have a very long operational life. However, there is no definitive consensus regarding how to determine their specific useful life. While there are transformers that have been in service for 30 to 40 years, there have also been major transformer failures and fires for those in service for relatively shorter periods of time. It is fair to conclude that while transformers are generally reliable, external interference and internal cumulative hazards often lead to premature failure.

The issues that affect the useful life of transformers may be categorized in two areas: manufacturing defects and operational issues. Manufacturing defects may result in service outages and shorten the expected life of transformers. In this article, we are focusing on the operational issues that affect the reliability and premature failure of transformers, including the following:

  • Electrical overloading and overheating
  • Harmonics (K factor is a method of quantifying the harmonic content of a current waveform. The factor is thoroughly described in ANSI C.57.110)
  • Grid disturbance
  • Lightning strikes
  • Load swings
  • Altitude if above 3300 feet (ANSI C.57.12.01)
  • Lack of testing and maintenance to evaluate the condition of transformers

All of the above result in insulation failures that in turn cause short circuits and arcing.  In the case of mineral oil-filled transformers, which are ignitable, this will further cause rupturing and fire.

In general, most transformer evaluation decisions are driven by occupancy, size of transformers and loading. My review of risk assessment reports that span several years reveal a vast deviation in evaluation of transformers and recommendations. In addition to standard tests such as dielectric absorption testing, ratio testing, etc., below are some suggested evaluation tips for transformers > 5,000 kVA, furnace and special purpose transformers, and GSUs:

NOTE: For meaningful evaluation, the results should be trended and interval of testing adjusted accordingly. If this is not done, a recommendation is warranted.

  • Gas chromatographic analysis of dissolved fault gases in hydrocarbon dielectric fluid – minimum annually. Consider installation of a sudden pressure relay and continuous gas monitoring system. The analysis should include testing for Furan and Corrosive Sulfur. The presence of sulfur in the oil causes severe corrosion. Transformer failures due  to the presence of sulfur are not very common but do occur. A reference test should be recommended.
  • Furan Analysis: Cellulose is a naturally occurring polymer of D-Glucopyranose monomers. The degree of polymerization (“n”) represents the average number of monomers in the polymer chain. The decomposition of paper is caused by the processes of hydrolysis, pyrolysis and oxidation. The degree of polymerization (DP-value) of paper was defined by IEC 60450 and it counts the number of polymerized glucose rings. During the paper decomposition, the DP-value is reduced and the tensile strength decreases. New cellulose has a DP-value of 1000-1100. When the “n” value drops below 250, there is a reason for concern and a recommendation is warranted for replacement of transformers or a contingency plan. The value of “n” is irreversible.  If the “n” value drops below 150, the insulation has very little mechanical strength and is close to failure.
  • Power Factor Testing: Insulation power factor tests are used to measure dielectric losses, which relate the wetness, dryness or deterioration of transformer insulation. Both factory and field-testing are performed to verify the insulation integrity of substation transformers. Power factor testing a two-winding transformer is conducted by energizing the winding at a known AC voltage (typically 10 kV for windings rated greater than 10 kV) with the common winding bushings shorted together.

The results of overall power factor tests on power transformers reflect the insulation condition of the windings, barriers, tap changers, bushings and oil. Modern oil-filled power transformers should have power factors of 0.5 percent or less, corrected to 20°C (68°F), for individual windings to ground (CH and CL) and interwinding insulations (CHL). The IEEE transformer specification states that the power factor of the insulation system shall not exceed 0.5 percent at 20°C.

Several insurance companies, manufacturers and electrical testing companies recommend PF testing every three-to-five years. Often this is not practical because the testing can only be completed offline. For this reason, users are reluctant to perform this important testing.  For GSUs, furnace and special purpose transformers, a great option to consider is installing continuous power factor monitoring systems.

The above suggested evaluations tips may increase reliability and prevent the premature failure of transformers. If you have any questions, please feel to contact me, as our team is always ready to help.