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Dry Gas Seal Failure Modes


Invented in the mid-20th century and typically equipped in process gas centrifugal, dry gas screw compressors and expanders, dry gas seals (DGS) are the preferred gas lubricated dry seal solutions available on the market. They have become the standard for new machines.

DGS are robust, simple, consume less power, and are more efficient in reducing leakage than their predecessor. Various configurations such as tandem with and without an intermediate labyrinth (Figure 1), single (Figure 2), and double (Figure 3) are available & shall be selected based on process requirements. In this article, we discuss the various DGS failure modes and how they should be addressed: 


Pressurized hold, also called settle-out condition, occurs when the compressor remains at a standstill, but the casing is pressurized. If an alternate process gas lacks sufficient pressure and flow, process gas enters the seal cavity through the process labyrinth and contaminates the primary seal. This causes seal damage when the compressor is restarted. Minimum ambient site temperature also must be considered as the seal will be at the same temperature during standstill conditions, which will cause the process gas to condense and deposit on seal face grooves.

To avoid this kind of failure, the seal gas must be supplied with the required pressure even during a blackout. An alternate supply of seal gas should be considered when gas is not available from the compressor discharge. But it should not change the composition of the process gas. A seal gas booster should be considered when alternate gas is unavailable.


The cause of the majority of DGS failures is contamination. This happens mostly during commissioning by not following OEM recommendations and best practices. Seal gas panel components including piping are properly cleaned and flushed with air, and end connections are blinded and dispatched to the site. However, site situations are always different. The piping upstream of the console must also be cleaned thoroughly including interconnecting piping between the console and the compressor. Corrosion inhibitors must be removed. The seal gas supply temperature dew point margin must be higher than or equal to the recommended value as per API. Failure to do any of the above will lead to contamination followed by degradation of the lift-off effect, friction between the static and rotating faces, parts deformation, O-ring extrusion, heat generation causing thermal shock on the rotating seat, and eventually failure of the rotating and or static rings.


Although a DGS is less susceptible to failure during continuous normal operation, it may happen due to upset conditions leading to contaminated seal gas supply or condensate formation as a result of pressure drop across conditioning equipment. The flow velocity requirement across the process labyrinth varies depending on the process gas, usually 5 m/s. High velocity must be considered for some processes. If available pressure is not enough, consider installing a seal gas booster which will keep pressure at the seal cavity higher than on the process side. Ensure that a properly sized coalescing seal gas filter is installed which will filter out particles above 3μm. The gap between rotating faces is 3-5μm (a human hair is 70μm). Additional requirements, as per the recent API 692 code, should be considered as necessary.


A separation seal, also known as a barrier or tertiary seal, is located in between the DGS and the bearing box. Its purpose is to avoid lube oil ingress from the bearing to DGS side during normal operation and minimize process gas flow to the bearing side in the event of DGS failure. Flow consumption is much less than the secondary side. But depending on the type of seal applied, enough flow is necessary to avoid oil ingress to the DGS side. Nitrogen is typically used but dry air can also be supplied if the process allows it and does not create an explosive mixture. On the other side, high flow is not desirable as it may over-pressurize the lube oil reservoir. The vent line must be checked regularly and any oil traces should be drained and rectified.


Reverse pressure occurs when downstream pressure is higher than the upstream supply pressure. If specified, a seal should be designed for reverse differential pressure as recommended by API. This must be confirmed by the DGS vendor as well. During reverse pressurization, contaminated gas or liquid droplets can travel from the flare vent line back to seal faces resulting in O-ring dislodging, loss of performance, and subsequent risk of seal damage. A differential pressure control valve with PDIT can be applied to avoid these issues. If not, necessary arrangements should be implemented so as not to reverse pressurize the DGS. Confirm flare line minimum, normal, and maximum pressure with the customer. Ensure DGS leakage gas does not create an explosive mixture with other hazardous gases in the flare.


The compressor casing may be depressurized after shutdown in case of over-haul, emergency shutdown, planned maintenance, or as per process requirements. DGS O-ring material must be chosen based on the depressurization rate. Consult with seal vendors if the decompression rate is different a standard application. If special considerations aren’t given to the selection of O-rings, they can be subject to explosive decompression due to rapid depressurization. Additionally, the decompression rate must be selected right at the basic design stage. Special attention must be given to avoid the Joule Thompson effect based on gas composition. This can lead to condensation of the gas and the process side may be exposed to Minimum Design Metal Temperature (MDMT). If material is not selected according to MDMT, the subject material may fail.


Gases and air have dew points which vary based on pressure, temperature, and type of gas (Figure 4). The gas used as a seal gas from the compressor discharge undergoes reduction in pressure and temperature which causes condensation. Similarly, when the dew point temperature is achieved, condensate forms. Eventually, droplets travel through the rotating and stationary seal faces where they will create a blistering effect resulting in failure of the seals faces.

The solution is to follow the rule of chemistry and perform a dew point analysis. The designer should check gas properties from the compressor datasheet and reconfirm these with the client as smaller changes in composition can affect the dew point. Plot the dew point line for possible cases, calculate the dew point, and check its margin from the supplied temperature. The delta T should be equal to or higher than that recommended in API. If the margin is less, gas conditioning will be necessary to keep the gas dry as it passes through the seal gas system. Only the most likely failure scenarios are addressed here. But DGS failure can be caused by various factors depending on the site situation.

■ Bhushan Nikam is a Project Engineer for a major turbomachinery equipment manufacturing organization. He holds a bachelor’s degree in Mechanical Engineering from the University of Pune, IN. He can be reached at

Source:  Turbomachinery Magazine


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