This article will use a case study as an example of one of the many cases seen in the field with a range of different manufacturers’ seals to provide a checklist of considerations for applications where product containment is essential.
Legislation surrounding leakages from rotating equipment sealing devices has led to the introduction of more stringent regulations, particularly relating to emissions and health and safety issues. Upgrading single seals to more compliant technology for mature assets has evolved from being a reliability issue into a requirement to provide effective containment, or prevention of the process fluid leaking to atmosphere.
In addition to selecting more modern sealing devices, there is often a need to introduce or upgrade a seal auxiliary system to further manage the risk of process fluids reaching the atmosphere. One such instance occurs when wet or dry secondary containment seals have been incorporated in addition to the primary seal faces that seal the process fluid. Dry containment seals1 have gained popularity over the past two decades. Specifically the refinery sector has used this technology for limiting emissions without incurring the cost of more traditional liquid dual mechanical seal auxiliary systems.
However, there is little written about monitoring of the condition of dry containment seals during operation, or how they behave in the event of high levels of leakage from a primary seal. According to The American Chemical Industry (API) 682, 4th edition, “there are specific concerns regarding reliability and integrity of dry containment seals when compared to wet buffer outer seals.”
A petrochemical plant had installed a containment seal on a process pump that contained Butadiene as the process fluid. No seal support system was applied. However, a pressure gauge was fitted to the containment seal cavity.
The seal operated at a temperature of 44 C, a seal chamber pressure of almost 8.2 bar(g) and a speed of 2,920 rotations per minute (rpm). After four years of operation, the seal catastrophically failed, and it was reported that there was a fire on the pump in question.
The seal was returned for inspection where the following was discovered. The primary (inboard) seal faces, although appearing scored and phono grooved, were intact. This suggested that the primary seal did not catastrophically fail, although heavy leakage could not be ruled out.
Abraded damage to the primary seal faces means that flatness was barely measurable. The abraded damage to the seal faces could have been a consequence of heavily contaminated process leakage or degraded product build-up within the containment seal cavity.
The containment (outboard) seal faces were totally destroyed, suggesting a catastrophic failure of the containment seal. Heavy build up of what appeared to be degraded process fluid was found within the containment seal cavity and around the outside diameter of the sleeve. It is suspected that this build up is a consequence of years of normal process fluid leakage over the primary seal faces into the containment seal cavity. The process fluid had then broken down (polymerised) once subject to atmospheric pressure and ambient temperature within the cavity.
The seal had been operating without any auxiliary system support for the secondary containment seal. A pressure gauge was used to monitor any increase in pressure within the containment cavity should the primary seal suffer high leakage. If the primary seal had suffered excessive leakage, this would have led to either excessive vapor leakage to the atmosphere or a back pressure within the containment seal cavity, depending on the quality of the leaked process fluid. If the containment seal was still in good condition to contain the process leakage from the primary seal, the pressure gauge should indicate a pressure increase providing the reference line to the gauge was not blocked. There were no reports of a pressure increase on the pressure gauge. This indicates that either the primary seal was still operating in a satisfactory condition or that the pressure reference line was blocked.
If high primary seal leakage occurs as a result of no auxiliary piping plans being in place, the gas lift grooves within the containment seal will fill with process fluid. If the process fluid has polymerised or broken down, these grooves will be ineffective and will not produce any dynamic lift, leading to seal face contact, overheating and eventual seal face failure.
In 2002, dry containment seals were recognized in the second edition of API 682. A series of piping plans offered to take leakage to a safe collection point. The basis for a containment seal is an Arrangement 2 seal (two seals per cartridge assembly with a liquid buffer fluid) with an API plan 71 seal support system as a minimum requirement (i.e. without buffer gas feed). The introduction of a buffer gas is covered with API Plan 72 and the collection/disposal of process leakage is covered by API Plan 75 and API Plan 76 (see Figures 2 through 4).