Processing systems/design

Are the Separators Really at Fault? Part 1—Design

The Savvy Separator series continues as we share case studies of troubleshooting separator problems. This article focuses on design issues. Brief problem statements, root causes, and lessons learned are given.

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Poor separation performance is typically blamed on the separator itself with the main target being the internals. However, after an analysis of the issues, the root cause is often found to be a failure in areas related to the separator/internals.

In this continuation of the Savvy Separator series, shortcomings in design, installation, instrumentation, and operation that lead to poor separator performance will be highlighted.

This article focuses on design issues. Brief problem statements, root causes, and lessons learned associated with case histories of troubleshooting separators are given.

A)    Scrubber tripping on high level

In a gas/oil processing plant, a compressor suction scrubber was periodically tripping on high-liquid level which, in turn, tripped the downstream low-pressure compressor. It was found that the scrubber was receiving enormous slugs of liquid leading to overfill and a high-liquid-level trip.

A small suction scrubber had been originally designed and installed because the liquid rates were low, being a wet-gas field. And because of the low rates, slugging was not considered in the design.

Lessons learned:

  • Flow rates and other process conditions are not steady. Process transients or flowline geometries can generate slugs.
  • Consider slugging potential for all systems including wet gas and provide sufficient holdup for said slugs.

B)    Compressor trip on high vibration

A compressor in a gas/oil processing plant was tripping off due to high vibration. High volumes of liquid were found in the casing as well as scaling on the impellers. Upon further investigation, it was found that the data sheet for the upstream scrubber contained a liquid phase with "combined" properties of oil and water, resulting in artificially high liquid density and interface tension compared to the hydrocarbon liquid phase, and consequently an undersized vessel and mist eliminator. A new larger scrubber was designed using the oil properties and replaced the old one.

Lesson learned:

  • Verify fluid properties in design data. Are they reasonable? All individual phases must be represented separately.

C)    Compressor trip on high vibration

Like the previous example, a compressor in an oil-stabilizer plant tripped on high vibration, and large volumes of liquid were found in the casing. The upstream scrubber vessel design was analyzed and found to be adequately sized. The vessel was opened, and the mesh pad was found to have been dislodged, leading to substantial bypassing. The mesh pad had not been properly supported. Top beams had only been placed on the middle section so that the mesh at the perimeter raised up, allowing for liquid bypass.

Lesson Learned

  • Ensure the mesh pad (or any mist eliminator) is properly supported on both the top and bottom for all sections.

D)    High water cuts and sacrificial anode current

A three-phase production separator had been designed with an inlet vane device and a coalescer pack to enhance separation. Operations was experiencing not only higher-than-expected water cuts, but there was also high current on the sacrificial anode. The vessel was then opened for inspection. The inlet device had been dislodged, and the coalescer pack scattered throughout the vessel. It was determined that large liquid slugs not considered in the design had caused the damage.

Lessons Learned:

  • Review process conditions for transient/slugging conditions.
  • Ensure inlet device and other internals are mechanically robust enough for the worst- case slug.

E)    Noisy separator with high water cuts

A three-phase separator not only suffered from high water-in-oil, but a noise could also be heard coming from the inside. On multiple occasions, Operations had opened the vessel and noted that the inlet vane device had been dislodged by inlet slug flow causing the shutdowns as well as damage to the vessel wall. Slug flow had been taken into account in the initial design of the inlet device and was redesigned using slug flow parameters from a transient pipeline simulator.

A further investigation showed that the inlet control valve was placed immediately adjacent to the inlet nozzle and was much smaller in diameter than the vessel nozzle diameter. The distance between the two was too short for the high-velocity jet formed by the control valve to dissipate/spread out. Although slugging was accounted for in the inlet device design, this higher velocity exacerbated the incoming slug forces causing the inlet device damage.

Lesson Learned:

  • Pay attention to inlet piping as it is a key part of separator design. In this case, design for a straight section of pipe that is long enough to allow for dissipation of jet flow caused by the upstream reduced-area pipe section/valve.

F)    Filter coalescer not separating

A filter coalescer unit was not removing liquid as expected. In fact, no liquid was being removed. The unit had demisting cyclones installed below the filter elements to remove the bulk liquid. However, it was found that the cyclone drainpipe was not designed long enough to be sealed in the liquid pool below. Hence, the cyclones were not separating, resulting in no liquid being captured in the vessel and flooding of the filters. In addition, even if the pipe was long enough, it was not clear whether the unit was prefilled with liquid to seal the pipe.

Lessons Learned:

  • Understand your equipment. Some mist eliminators such as cyclones must have drainpipes sealed in the liquid to prevent gas bypass.
  • Added tips: Design drainpipes for self-venting flow and with less than 50% of the available static head of only liquid to account for foamy liquids and for the drainpipes to end 100 mm below the trip level.

G)   Liquid carryover from a vertical scrubber

A vertical scrubber, suffering from high liquid carryover, had been designed with demisting cyclones at higher-than-recommended rates per cyclone in order to reduce the vessel diameter. There was no room to add cyclones, and the vessel had to be replaced.

Lessons Learned:

  • Check the designs. Do not simply accept vendor or contractor designs. Question what does not make sense.
  • Understand the operating range of your equipment.
  • When designing with proprietary equipment such as cyclones, always check with the technology supplier.

H)    Compressor trip in an ethylene plant

Hot cracked gas is cooled in a vertical quench tower. The gas enters the bottom of the tower flowing upward against cooling water sprayed in at the top. At the top of the tower, the cooled gas passes through a horizontally flowing vane pack to remove entrained water and cracked condensate droplets. In this particular case, the downstream compressor tripped due to excessive vibrations and excessive pressure drop shutting down the plant.

An investigation showed that a) the vane pack blades were fouled with scale and polymer; b) the drainhole in the bottom sealing plate of the vane pack was also plugged; and c) the vane pack drainpipe lacked a liquid seal. All three issues led to excessive liquid carryover that caused the compressor trip. In addition, the cleaning of the vane pack required more plant downtime because it was designed as a segmented unit (multiple individual vanes are combined as vane segments using welded connections).

The segmented vane pack was replaced with a new one with vanes that could be individually removed for cleaning. A new fouling-resistant drainage system (e.g., larger-diameter drainpipes, larger vane trough) with a liquid seal was also installed.

Lessons Learned:

  • If fouling is known to occur such as in quench towers, design for ease of cleaning and to reduce downtime. In this case, design the vane pack with individual vanes that can be removed for cleaning.
  • Review the design for places that can plug and redesign accordingly.
  • Know the requirements of your mist eliminators (including the operators). They typically require liquid seals. Ensure that there will be a liquid seal at startup. Discuss modifications with design experts.

I)      Amine absorber exceeding amine concentration in water in natural gas plant

In an amine absorber, sour gas enters the bottom of the tower where it is water-washed to remove contaminants/solids. The gas then flows up through chimney trays into the amine wash section consisting of structured packing. Amine is fed at the top, flowing downward through the packing and contacting the rising gas from the chimney trays.

The absorber design was a typical one except for one modification: the chimneys were much taller than previously used.

The wash water that is distributed over the incoming gas is drained into a public sewer system. In this case, the wash water exceeded the allowable amine concentration for disposal.

An investigation corroborated two causes for the high amine concentration.

1) As amine from the upper amine packed section fell onto the top of the chimney tray, the splashing caused small droplets.

2) A gas backmixing within the chimney tray was occurring where some gas that flowed up one chimney was recycled back down another chimney into the water wash section again. This backmixing entrained the small drops of amine caused by the splashing mentioned above.

The solution to this issue was to install high-density wire mesh around the openings of individual chimneys. This absorbed the splashing, reducing the amount of small droplets, and reducing the backmixing.

Lessons Learned:

  • Small drops can be created in unexpected locations (such as falling down by gravity), not just at the inlet.
  • Once the physics of the problem is understood, a solution can be more easily found; in this case, a wire mesh.
  • Look for recirculation zones as vapor does not always go upward in a column.
  • Do a thorough review of new design even if it differs slightly from previous designs.

J)    Two-phase separator noise

After hearing noises from within a vertical suction drum, an emergency shutdown revealed that the inlet vane diffuser became dislodged with severe damage to the inlet vane and vessel wall. Upon further inspection of other similar vessels, three other separators had severe damage and four others had minor cracks on the vane inlet ladders and bottom/top plates. This emergency shutdown had severe production losses, and the vessel wall was compromised, which needed repair.

Upon computational fluid dynamics (CFD) and finite element analysis (FEA), it was found that flow-induced vibration caused damage to large-diameter inlet vanes. Stiffening with thicker plates, continuous welds, and a new attachment design resolved the issue. This experience led to new design specifications for inlet nozzles nominal pipe size (NPS) 36 in. or greater with inlet vanes diffusers in which a CFD and an FEA must be done prior to fabrication. The lowest natural frequency must be greater than 15 Hz. Vane ladders must have a thickness of 3 mm, and top and bottom cover plate thickness must be 5 mm.

Lesson Learned:

  • Internals should be designed not only for mechanical loads such as slugging and differential pressure, but for fatigue due to flow-induced vibrations, especially internals with long spans.

K)    Poor oil/water separation in a horizontal separator.

A production train consisting of high-pressure (HP) and low-pressure (LP) three-phase separators and desalters was not meeting oil or water specifications at 50% of design rates. The LP separators were doing the bulk of the oil/water separation. The high water in oil from the LP separators affected the desalter performance.

The poor separation was caused by a) the inlet piping (bends, ups, and downs) causing slug flow and poor distribution into the separators, and b) water recycle.

  • Water from the LP separator was routed to the inlet of the HP separator to enable a water continuous flow.
  • Water from the electrostatic separators was routed to the oil phase of the LP separator.

The recycle water was oily, and the recycle pumps sheared the oil into small droplets that could not be agglomerated in the piping or settled out in the separators. The mixing of the recycle water into the oil phases contributed to the higher water in oil as well.
Separation and capacity specifications were finally met after

  • Inlet piping configurations to both the HP and LP separators were modified to eliminate slugging and to improve flow distribution into the vessels.
  • Water was rerouted to the water phases of the HP and LP separators.
  • Plate packs were added to the HP and LP vessels.
  • Test separator was used for additional capacity.
  • Water wash was increased to the desalters to improve their performance.

Lessons Learned:

  • Inlet piping can significantly impact separator performance.
  • Recycling water from downstream vessels to upstream vessels can affect separation performance and should be done with expert review. It is preferred to process the water in its own cleaning system.
  • Small droplets are not formed just at the incoming flow.

L)    Two-phase separator carryover

A gas plant was shut down after significant liquid hydrocarbon was entrained into the gas leg affecting downstream processes.

The vessel was designed by a contractor according to API 521 specifications in which the vessel is designed to remove droplets greater than 450 microns. However, the separator was designed with a simple elbow directed at the vessel head and with an inlet momentum much higher than recommended. The liquid level was also set too close to the inlet. The impact of the inlet flow on the liquid interface caused small liquid droplets to be generated/entrained. Small drops were not able to settle out in the small vapor space.

To remedy the issue, liquid levels were reduced to provide more disengagement area/lower velocities, and the elbow was replaced by an inlet vane device. Droplet generation at the liquid interface was eliminated.

Lessons Learned:

  • Small droplets can be caused not only by impact on hard surfaces, but on liquid surfaces.
  • Sufficient space is needed not only for liquid droplet disengagement, but to mitigate entrainment.

M)   Liquid carryover from a horizontal separator

As a last example for the reader to ponder, a three-phase horizontal separator was suffering from high liquid carryover. A mesh pad had been installed that was submerged in the liquid phase with the height determined by a weir. It was found that the unsubmerged mesh pad area was too small by about 30%.

  • What do you think are the root causes?

The overall lessons learned are:

  • Always consider transient/slugging flows regardless of the liquid rates.
  • Question the fluid properties. Is there really only one liquid phase?
  • Inlet piping is a key part of separator design.
  • Mechanical supports are just as important as the internals.
  • Look for where small droplets can be created.
  • Recycle flows can be detrimental.
  • Understand how your equipment works and its requirements.
  • Thoroughly vet new or slightly modified designs.
  • The root cause may lie outside the separator. To paraphrase a well-known idiom, “Think outside the vessel!”

If you have a separator story to share in a future article, the author may be reached at