Centrifugal Pumps and Centrifugal Compressors are classified as driven equipment which are widely used in the oil and gas industry. It’s important device for solids control system. Centrifugal Pumps is primarily used to boost the operating pressure and transfer liquid (like drilling mud) and gas respectively in a safe and reliable manner. Process containment is one of technical integrity and safety barrier classified under Safety Critical Element(SCE). Centrifugal Pumps is one of solids control equipment.
PROCESS CONTAINMENT FOR ROTATING EQUIPMENT
In general, Safety Critical Element (SCE) consist of 8 barriers as shown in Figure 1.
Most of the Rotating Equipment are classified under the Process Containment Barrier. Therefore, it has become important that the rotating equipment engineers take precautionary steps to ensure that driven equipmentsuch as pumps and compressors perform their intended functions, including the safety critical function to contain the product from leaking into atmosphere/environmentin anuncontrolled and unacceptable level.
The primary components of centrifugal pumps such as the mechanical seal, and DGS for Centrifugal Compressor will be the focus, the threat and damage mechanisms will be discussed.
MECHANICAL SEAL FOR CENTRIFUGAL PUMPS
Mechanical Seal is a critical component in centrifugal pumps which primary function is to contain the fluid passing through the pump. There are various designs of mechanical seals as per API 682, but they are basically divided as per the following categories;
- Arrangement 1 – Single seal or one seal per cartridge such as Piping Plan 11, 21 and 31.
- Arrangement 2 – Double Seal or 2 seals per cartridge with space in between having pressure less than the seal chamber pressure. Example of this seal is Piping Plan 52.
- Arrangement 3 – Double seal or 2 seals per cartridge with space in between the seals using externally supplied barrier fluid with higher pressure than the seal chamber pressure. Examples of this seal are Piping Plan 53A, 53 B and 53 C.
The mechanical seal designed to API 682 specification has life of at least 25,000 hours without any need for replacement. However, the current threat such as sand from the wells or particles in the crude oil (including produced water) will reduce the life of the seal causing premature failure, increase the cost of maintenance, and a major threat to safety in terms of process containment.
Arrangement Type 3 is the choice of design of mechanical seal for cases where no leakage of product to atmosphere is acceptable. It is also a choice if the product is dirty. This design could provide higher degree of safety protection by preventingproduct leakage into the atmosphere or environment. The use of externally pressurized barrier oil, in the event of inboard seal failure, the product is contain within the pump until the pump reaches a safe shutdown. The crucial information is to monitor the pressure of the barrier oil so that it stays higher than the minimum allowable pressure. If the barrier oil pressure is allowed to go below the minimum pressure, it will act like a Plan 52 and will not serve its intended function.
Since most of the barrier seal fluid is using a non-volatile oil, the leakage is always visible and it is often misunderstood as seal failure. The question is: how much leak is acceptable? Based on API 682 seal performance criteria, the typical leakage rate is about 5.6 g/hr. (estimated 6.6 ml/hr. for PETRONAS Logamol ESP 10) or 2 drops/min. However, when the seals have been put into service, there are many factors that could affect the seal leakages as follows;
- Viscosity of the oil. It is also a function of the operating temperature of the barrier oil.
- Excessive converging and divergent sealing gap due to thermal and pressure distortions respectively.
- Stabilization of the period or burnt in period where pressure and temperature of the seal try to stabilize. This is normally during start up after the installation of new seal, when the pair of seal faces aligns to form a uniform pair.
Due to the various factors affecting seal leakages, one has to analyze the seal performance in detail prior concluding that the seal has failed and deem for replacement.
Result and Discussion on Mechanical Seal Piping Plan 02/53 C
About 4 years ago, operation experienced mechanical seal failures on centrifugal pump. They were classified as infant failures, because the seal failures occurred within a short time after commissioning of the pumps in each case. On some occasions, the barrier fluid was seen black in color. In all cases, the pump was brought into a safe shutdown. The standard piping plan 53 C is shown in Figure 2 in Appendix.
As a best practice, flushing and cleaning the overall fluid tanks and piping system were introduced. Upon inspection, some of the seal faces was found with carbon deposits as shown in Figure 3. This could be due to the seal faces operating at higher temperature. It is suspected some rust particles and contaminants from seal failure could have contributing to oil contamination, which could affect the cooling system and seal reliability. During site investigation, it is also found that one of the valve integral to the seal oil system was producing rust particles when it is been operated. It is likely that the valve hadsome internal rusting due to poor preservation during project phase or long shutdown period.
On one occurrence, the seal exhibited leakage more than the OEM allowable limit without any blackish colour appeared in the oil. The initial OEM allowable limit was about the limit specified by API 682. When the seal was dismantled and inspected, there was no physical damage observed. Upon pressure testing as per API 682, the seal dperformance still meets the requirement. This indicates the seal did not fail, only showed higher leakage in service.
Upon discussion with OEM and reengineering, the allowable seal leakage rate was increased. However, after start up and completion of endurance testing, the DE and NDE seal showed a leakage rate of about 50% and 75%higher than the revised allowable leakage rate respectively. In order to continue to operate the seal with higher leakage, a proper safety risk assessmentwas carried out by considering the product safety, pump neighboring condition, operating condition of the seal such as temperature, vibrationand the barrier oil safety information. The seal oil temperature, temperature rise at seal and vibration profile after 72 hours endurance testing considered stable and normal, within the API 682 and API 610 requirement respectively.
Hence, with the above assessment and close monitoring, the seal recorded operating life more than 4 years to-date. As of today, the leakage rate has drop to about 50% below the OEM allowable limit. Thus, the cause for the initial higher leakage is suspected due to longer stabilization period needed for the seal. For Arrangement 3 seals, such as Plan 02/53C, it is imperative to monitor the pressure, level and refilling period of the Constant Pressure (CP) pot to determine whether the seal has failed and needs replacement. This analysis does not conclude that higher leakage is a norm but it should not be the only criteria to determine the need for a seal replacement. Therefore, it is important to understand various factors before deciding whether a seal has failed and due for replacement. A similar spare pump, does not exhibit any visible leakage during operation.
Best Practices sharing for Mechanical Seal Design, Operation and Maintenance
In reality, the practical way to prevent a premature seal failure, is to adopt the best practices which emphasis on the Five-Point Check for the correct installation of the mechanical seal namely the shaft end play, shaft run out, radial deflection, concentricity and shaft perpendicularitycheck. Besides this, tightening torque of the set screw or shrink disc (used to engage the shaft and rotating component of the mechanical seal) shall be given high priority during seal installation such as hold point for proper torqueing. This shall be identified as the 6thPoint Check. Appropriate tools for this particular application arerequired because of limited access space. These tools should be readily available. Any attempts to tighten without appropriate tools would be inadequate, at the very least, uncertain.
In cases of product containing dirty and abrasive services, piping plan Arrangement 3 is recommended as this could avoid abrasive particles from product entering into the seal faces. The use of Piping Plan 31 with Cyclone Separator can be applied in services containing solids with density at least twice of the product fluidin order to work effectively and protect the seal faces from detrimental damages. Inindustry, it is normally used in moderate contaminated services and applied insingle seal or in combination with Arrangement 2 seal (piping plan 52). The common failure mode for this device are as follows;
- Clogged separators
- Dirty discharge line
- Wear out from the velocity of the abrasives from product
This device, which is normally built with austenitic stainless steel such as SS 316 material, can be internally hard surface coated with tungsten carbide to prevent erosion where possible. In some of its application, the design is available with replaceable erosion resistance material insert.
At site, it is recommended to monitor the temperature profile of the seal and its associated piping system to understand the performance of the seal and its system. The quality of buffer fluid has to be checked regularly to understand the seal performance and take proactive measure to avoid seal failure. If the fluid is dirty and appear contaminated, then flushing the tank and replacement of buffer fluid is necessary. This may applicable to barrier oil if the oil found to be abnormal such as blackish in colour. This is one of the simple predictive tools available to-date to monitor the condition of the seal and improve its reliability.
The sand in crude oil will cause erosion and impingementto the casing and also damage to some of the critical components of the casing such as center bushing seat as shown in Figure 4, and casing mating surface due to suspected improper gasket installation as shown in Figure 5. Thus, the gasket selection and correct installation is paramount to casing joint integrity.
Depending on the analysis of the failed component or experience, the wearingand bushings can be redesigned to avoid turbulence effectand reduce erosion. The selection of casing material also can be improved by selecting a higher erosion resistant material from the material class outlined in API 610.
PETRONAS has discussedwith OEM to modify the pump internal components and reduce the exposed area of the casing at critical location. This has decrease the damage mechanism due to erosion.
DRY GAS SEAL FOR CENTRIFUGAL COMPRESSOR
DGS is widely used as the sealing component in Centrifugal Compressor to provide the sealing between casing and the rotating shaft. The commonlyused of DGS Seal arrangement would be the tandem seal in the industry. In this arrangement, primary and secondary seal are arranged in series. The recommended DGS would be the Tandem DGS with intermediate labyrinth designfor hydrocarbon services as shown in Figure 6 unless where not possible.
Dry Gas Seal System Design Standards for Centrifugal Compressor Application.
DGS Best Practice Sharing on Design, Operation and Maintenance
The intermediate labyrinth design is highly recommended for the DGS as shown in Figure 6 for the following reasons;
- Catastrophic failure of one seal can cause a failure of the second seal. The presence of intermediate labyrinth will isolate migration of failure to the other seal e.g. contaminants such as particles and liquid.
- In case of catastrophic failure of the seal faces on both primary and secondary seals, the intermediate labyrinth could provide some level of sealing and protection instead of allowing high flow of product gas venting to atmosphere or migrating into the bearing housing.
It also important to consider the construction of the DGS internals during the design phase. In order to increase the safety level, the DGS design shall be consider that a catastrophic failure of one of seal will not affect the mechanical integrity of the other seal. This will be the assurance that when a catastrophic failure occurs to one seal, the other seal is healthy to give the protection until a safe shutdown is achieved.
The industry known DGS safety concernis the use of instrument air as Separation Gas for bearing seal. It is highly recommended the use of inert gas such as nitrogen for the Separation Gas instead air for not allowing any combustible mixture of hydrocarbon and air at the secondary vent. If air is used, then it shall be analyzed carefully on case to case basis to provide lean mixture. The analysis shall cover the worst case scenario such as the secondary seal failed and not been detected. When buffer gas with nitrogen is introduced as secondary seal gas supply, presence of combustible mixture is minimal in the secondary vent. However, design consideration still need to be given for worst case scenario. The use of secondary vent flow monitoring system provide the detection of secondary seal health but the design has to give due consideration to the backpressure. The secondary vent should allow unrestricted gas flow during a catastrophic failure. The detection sensitivity of the device is reliable only if the separation gas leakage into the secondary vent is stable and constant. The use of flammable gas detector at secondary vent is recommended when a reliable instrument is available. This can detect for any presence of combustible mixture. The primary seal vent shall be routed to the flare.
Contamination is the leading cause for DGS degradation and low reliability. For example, the quality of instrument air such as presence of liquid has to be given attention. The quality of air shall be dry and clean but at times due to anomalies, condensate of water could presence. If the air compressor is designed with lubricated oil, then there is possibility some of the oil could presence in the air if the air/oil separator at the air compressoris not working properly. Theworst case would be that the contaminated air could travel into the secondary vent and some oil in the form of mist or liquid could migrate into the secondary seal and damage the seals.
In order to prevent this event, the air compressor used for instrument air shall be oil free type. As for the oil flooded type air compressor, it is imperative to monitor the quality of air and perform draining at the secondary vent drain line whenever the unit is down, to monitor if there is any hidden liquid presence in the system. The provision for such drain line shall be incorporated in the design. The risk of damage will be further magnified if the DGS is designed without intermediate labyrinth.
As the technology progress, some of the OEM has developed advanced bearing seal that limit migration of oil from the bearing which could help and reduce the effect of lube oil migration from the bearing. User need to assess this development in technology on case to case basis prior to application. Success stories should be shared for continuous improvement in the DGS reliability.
Based on the case study, best practices and experience shared, there are various damaging mechanism that could affect the process containment of the centrifugal pumps and compressors especially on the mechanical seals, casing and DGS system.
Some of the best practices and lesson learnt shared from this article are as follows;
- Preservation of piping systems including valves during construction is particularly critical with lube oil and seal oil systems where rust particles can damage mechanical seal assemblies. Flushing and cleaning procedures should be addressed.
- Subsequent to any seal failures, it is essential to carry out full flushing and cleaning of seal oil systems and piping networks. Removal of contaminants from the previous failure from the entire oil system will assure flawless start up.
- The mechanical seal assemblies installation should comply with the torqueing requirement stated on the assembly drawing to assure safe conditions will be achieved. ITP should have hold points to verify bolt torqueing on all critical bolts during mechanical seal installation.
- Various factors shall be considered prior to deciding a seal has failed and due for replacement. Discussion with the seal OEM is important to understand seal performance and leakage rate.
- Cyclone/Separator installed for Piping Plan 31 can be internally coated with hard surface or with replaceable erosion resistance material insert to prevent internal erosion. Where internal coating or insert is not possible due to the size, suitable erosion resistant material can be selected. The device shall be design properly based on the size and density of the solid in the product.
- The design for handling abrasive product like sand contaminationshall be addressed during design. Discussion with OEM is necessary to design centrifugal pumps to meet those requirement. This will ensure seal and pump reliability, safety and justify its life cycle cost during entire service life.
- Tandem Type DGS arrangement shall be designed with intermediate labyrinth for safety reason especially with hydrocarbon services. This increase the safety level of the seal in terms of process containment.
- Inert Gas such as Nitrogen shall be used as Separation Gas. If air is used, then careful consideration shall be given in the design to provide lean mixture.
- Quality of the separation air if used shall be given attention where applicable. The air compressor used shall be oil free type to prevent liquid carry over in the separation air.
DGS : Dry Gas Seal
DE : Drive End
ITP : Inspection Test Plan
NDE : Non Drive End
OEM : Original Equipment Manufacturer
SCE : Safety Critical Elements