Liquid Levels and Density
(Special Shared Content with The Distillation Group)

Case histories with DP cell problems

Differential pressure (DP) cells are the most often used level measuring device in the process industries. Differential pressure cells measure the pressure difference between two points and send a differential pressure reading to the plant control system. Typically, DP cells are rated in inches of water equivalent. Standard ranges include 0 to 20, 0 to 50, 0 to 100, 0 to 200, and 0 to 500 inches of water differential pressure.

The control system converts the DP cell reading into a liquid level based on an assumed specific gravity inside the vessel. Levels based on DP cells can err for different reasons. Previous columns have covered many reasons DP cells or sight glasses can give false readings. This column covers some case histories of specific DP cell problems.

Cryogenic unit with two operating modes

The first case involves a cryogenic field extraction unit that had two possible operating modes. The first mode was an ethane rejection mode where ethane was sent overhead. The second mode was an ethane recovery mode where the main tower switched to a demethanizer operation. The overhead product was methane and lighter and the bottoms product was ethane and heavier. The recovered liquid (tower bottoms) was sent to a separate plant that segregated the liquid stream into consumer LPG and petrochemical feeds.

The plant started up in the ethane rejection mode successfully and operated there two years. After downstream facility modifications were made, the plant shifted into the ethane rejection mode. Tower problems occurred immediately. Major problems were intermittent flooding of the tower and inability to effectively control coldbox heat integration.\

Figure 1: Effect of improper liquid levels in overhead drum

Field troubleshooting identified the culprit as changed densities in the tower. The ethane recovery mode had lower liquid densities. The lower liquid densities inside the tower caused 'measured' liquid levels to be lower than the actual liquid levels. Normal tower boot liquid level variations caused liquid back-up into the reboiler return line. Normal overhead drum liquid level variations (Figure 1) created liquid entrainment into the overhead vapor going to the heat integration in the coldbox. The problem was especially acute in the overhead drum.

Calibrating the liquid level measurement for the new densities immediately corrected the operating problems.

Water hold-up causing level problems in overhead reflux drums

Many drums in hydrocarbon systems have water boots and separate water levels controllers. Typical services that have these on overhead drums include atmospheric columns, coker main fractionators, visbreaker atmospheric columns, and fluid catalytic cracker (FCC) main fractionators, among others.

On one FCC main fractionator, a fouled water level measurement resulted in pump cavitation, seal problems, and increased maintenance costs.

Immediately after a turnaround, the FCC started up without problems. However, after several weeks of operation pump seal problems on the reflux pump became common. Field troubleshooting quickly identified that the pump was cavitating. The initial conclusion was that the net positive suction head (NPSH) available was insufficient. This was puzzling because the pump had always worked before. An alternate idea proposed at this point was that the pump was damaged, creating a need for a higher NPSH. One pump of the two parallel pumps in the service was pulled and inspected. No apparent reason for NPSH problems was found with the pump. Design of the piping from the drum was checked. Again, no source of NPSH problems was found.

Figure 2:  Blocked water level taps

Over time, the new operation was accepted as normal. However, the situation continued to nag on some of the operators involved. While on site for operator training, the author was asked about this problem and a new troubleshooting effort started. Field data was gathered and compared to operating data. One suspicious observation was immediately obvious. The water level measured in the drum never seemed to vary. The connections to the water level instrument were blown out and the instrument placed back in service. The measured water level immediately jumped from 54% of range to 100%. The water level was above the upper water level tap. A plug in the line to the water level instrument had blocked the instrument at 54% of range.

Actual water level varied down to nearly zero to up to the internal draw-off pipe to the unstabilized naphtha pump. Two problems were damaging the pump. First, water density is much higher than the naphtha density. The reported naphtha level in the drum was much higher than the actual naphtha level. Calculations showed that under some conditions the flow to the pump could be cut off entirely. At other times water ended up in the pump suction. Sudden water slugs to the pump dramatically increased power load and caused pump damage.

Review of operating records showed that at the same time pump seal failures increased, gas plant operation became less stable. The water in the unstabilized naphtha increased water entrapment in the gas plant absorber-stripper and increased propylene losses. The problems, seemingly unconnected, had the same cause, a single level instrument giving incorrect readings. Supporting evidence came from trends in main fractionator pressure drops. The main fractionator pressure drop had been gradually rising. Water in the main fractionator reflux vaporizes inside the fractionator and deposits solid salts. The salts plug trays and packing, increasing pressure drop.

Unit operation substantially improved with the level instrument back in service correctly.

Further Reading

The full text of this article, including all eight figures can be found at Hydrocarbon Online, Tech Talk, or can be obtained by sending a message to the Distillation Group paper server. Send an e-mail to techrequest@distillationgroup.com with the number 094 in the subject line to receive a PDF copy of the article.

Questions and Answers

High-capacity trays: what is a hanging downcomer tray?

Subject: High-capacity Trays
Date: Mon, 5 Mar 2001 16:31:01 +1100

Andrew,

What is a hanging downcomer tray (can you provide a picture)? How does it increase capacity?

L., Asian Refiner

Subject: High-capacity Trays
Date: Thur, 8 Mar 2001 10:32:00 -0600

Overview

High-capacity trays can greatly increase distillation tower capacity. However, they should be used with caution. Many plants have had successes, others have had repeated failures. Often, the difference between success and failure is understanding the performance limits and compromises in advance. Effective application of high-capacity trays requires more precise knowledge of operating conditions and flexibility requirements: greater attention to design detail: and careful installation.

Normal versus High-Capacity Trays

A normal tray consists of an active area where mass-transfer takes place, a downcomer to move the liquid from tray-to-tray, and an open area where vapor-liquid disengagement takes place and the vapor moves from tray-to-tray. The tray's ability to mix, then separate vapor and liquid limits the tray capacity. A standard tray has an area under the entering downcomer and over the exiting downcomer where liquid and vapor cannot mix on the tray deck. This 'inactive' area is what high-capacity trays attempt to use.

The major type of high-capacity tray that has found wide acceptance are those that convert the area under the downcomer to active area. Figure 1 shows an illustration of a tray with the area under the downcomer converted to active area [1]. Figure 1 is a side view including the flow of vapor and liquid.

The UOP Multiple Downcomer (MD) tray was the first commercially successful tray with active area under the downcomers [2]. The MD-type tray still makes up the majority of high-capacity tray installations. Recently, several variations of trays with increased active [3,4,5,6] area have been aggressively marketed. Increased numbers of tray failures have come along with the aggressive marketing of high-capacity trays [7].

How High-Capacity Trays Work

First, the area under the downcomer must be made into active area, either with perforated holes or directional valves. Second, something must make sure that the downcomer still works. To work, the downcomer needs to be able to pass liquid from a higher tray to a lower tray.

If vapor rises through the downcomer, liquid is prevented from flowing down. The result is a flooded downcomer, flooding the tower in turn. The solutions to keep vapor out of the downcomer are distance, head, direction and momentum. Distance refers to the distances between the tray active area and the downcomer. Head is the height of liquid in the downcomer and the pressure exerted by the liquid. Direction is the direction of movement of the liquid and the vapor. Momentum is the speed of the moving liquid and vapor. A combination of some, or all, of these is used in high-capacity trays to prevent the downcomer from flooding.

Figure 3: Side view of hanging downcomer tray

The distance required between the bottom edge of the downcomer and the tray deck varies for each variant of the high-capacity tray. However, for any given design, a range of useable distances is possible. If the downcomer is too close to the tray deck, the froth from the rising vapor cannot escape sideways. The downcomer outlet area is choked and the tray will flood. If the distance it too great, two things can happen. First, the falling liquid from the downcomer can have enough momentum to go right through the holes in the tray below. Second, the downcomer may be so short that it lacks volume to disengage the froth into vapor and liquid. The downcomer backs up and the tray floods at relatively low liquid rates.
Liquid height, or head, exerts a pressure equal to its height times its density. Vapor is prevented from rising up the downcomer by the liquid head. The liquid head in the downcomer is also set by the pressure drop of the liquid leaving the downcomer. The higher the pressure drop, the higher the liquid level in the downcomer.

In a high-capacity tray, the clearance needed to allow vapor to escape from under the downcomer creates a large downcomer opening. The large downcomer opening does not impose sufficient back pressure to hold a liquid level in the downcomer. A restriction in the downcomer creates sufficient pressure drop on the liquid that a head builds up and vapor cannot bypass.
Direction and momentum can also help to prevent vapor bypassing up the downcomer. In some designs [5,6,8] the vapor rising through the active area under the downcomer is sent through slots angled across the tray instead of through conventional slots.

Dynamic Seals and What They Mean

Every variation of high-capacity tray has its own combination of features that are supposed to make the tray work correctly. Nevertheless, one thing that all the commercial high-capacity trays (that convert the downcomer inlet area into active area) have in common is a dynamic seal on the downcomer. This is important. It restricts the flexibility of the tray and makes installation tolerances critical.

What is a dynamic seal? Figure 4 compares a conventional tray with a positive seal, a conventional tray with a dynamic seal, and high-capacity trays with dynamic seals. Figure 4A shows a conventional tray with a positive seal. The bottom edge of the downcomer is below the top edge of the outlet weir. The outlet weir holds a liquid level on the tray and seals the downcomer. At higher liquid rates, the conventional tray may even have its outlet weir chopped off (Figure 4B). This reduces the tray pressure drop (and can increase the tower capacity). However, now the only thing sealing the downcomer is the height of liquid back up in the downcomer. If liquid rates are high, this will work. All high-capacity trays use dynamic seals. Figure 4C shows a high-capacity trays with a dynamic seal.

Figure 4:  Static and dynamic seals

Why are dynamic seals important? The only thing preventing vapor bypassing up the downcomer and flooding the tower is the height of liquid in the downcomer. A minimum amount of liquid must be kept in the downcomer to prevent vapor from bypassing through the downcomer. This sets the minimum liquid handling rate of any given tray. Filling the downcomer up with froth and backing liquid onto the tray above sets the maximum liquid rate of the tray. The tray can only operate between these two limits. A conventional tray's downcomer (with a positive seal) does not have the same lower operating liquid rate that a high-capacity tray needs. High-capacity trays have less operating flexibility than conventional trays.

This issue of minimum liquid to seal the downcomer is always a challenge because it conflicts with the priority objective of maximizing downcomer capacity. Vendors tend to err on the side of high capacity. Turndown is almost always less than predicted.

While the dynamic seal places a limit on tray flexibility from one direction, two other factors restrict the liquid flexibility of high-capacity trays from the other direction. First, the effective height of the downcomer on a high-capacity tray is less than that of a standard tray on the same tray spacing. Second, tray spacing is often changed when using high-capacity trays to increase the number of distillation stages in the same shell. Nearly all high-capacity trays have shorter effective downcomer heights than conventional trays. Downcomer height gives flexibility to handle liquid rate changes. The shorter downcomer height gives less flexibility.

What happens when the dynamic seal unseals? Two major things can happen. The first is if the downcomer completely unseals. Vapor heads up the downcomer, bypassing the liquid. If the high-capacity tray has a perforated (sieve) active area, liquid now falls through the tray deck. No vapor-liquid mixing occurs. Little fractionation takes place.

Second, if the downcomer partly unseals and the liquid and vapor rates are correct, the entire active area plus the downcomer area can effectively turn into a dual-flow tray. In a dual-flow tray, the vapor rises and the liquid falls through the same hole. A high-capacity tray that unseals and acts like a dual-flow tray will have less capacity than the correctly functioning high-capacity tray. Whether or not dual-tray mode failure occurs depends on the liquid and vapor loads, fluid properties, and tray type and design. Failure modes can switch back and forth between bypassing and dual-flow operation with very small changes in tower loads. This makes troubleshooting high-capacity trays very difficult.

In addition to the downcomer limitations, high-capacity trays often have very high hole areas on the tray deck. High hole areas pass more vapor. They also restrict vapor handling flexibility. Combining downcomer limits with vapor handling limits, high-capacity trays can have very limited flexibility. As a rule, the higher the capacity through a given tower diameter, the less flexibility is available. In fact, extreme designs approach point operation devices. Point operation devices are trays that will only operate at one specific loading point. They have no turndown capability.

How Much Can High-Capacity Trays Help You?

Over-zealous capacity claims have been made for many types of high-capacity trays. This has lead to several failures of towers to meet expected capabilities. If too much vapor goes up through inlet area devices under the downcomer, tray efficiency may suffer significantly. For a 'conventional' hanging downcomer high-capacity tray, don't expect capacity increase in a revamp to exceed the percent gain in active area. This assumes a one-to-one changeout, with no efficiency effects, change in tray spacing, or change in number of flow passes.

Further Reading

Further reading can be obtained by sending a message to our paper server. Send an e-mail to techrequest@distillationgroup.com with the three digit number of the reference wanted in the subject line to receive a PDF copy of the article (remember to include the zero at the front of the number, if noted).

077 Should You Switch to High Capacity Trays?; A. Sloley; Chemical Engineering Progress, January, 1999: 23-35.
076 High-Capacity Distillation; A. Sloley; Hydrocarbon Processing, August, 1998: 53-60.
073 High Capacity Trays for Realistic Revamps; A. Sloley; Chemical Engineering Exposition and Conference, Houston, 3-4 June, 1998.
070 High Capacity Trays - Basic Choices; A. Sloley; Distillation Technology Conference, Orlando, April 2-4, 1998.
065 Customized Tower Revamps - Success and Failure; A. Sloley; Fuel Technology and Management, January 1998: 48-50.
040 Why Towers Do Not Work: Part II; A. Sloley, S. Golden, and E. Hartman; National Engineer, Vol. 99, No 9, September 1995: 16-22.
038 Why Towers Do Not Work: Part 1; A. Sloley, S. Golden, and E. Hartman; National Engineer, Vol. 99, No 8, August 1995: 19-34.

References

1. Chuang, K. T.; Everatt, A. E. Gas liquid contacting apparatus. U.S. Patent 4,504,426, 12 March 1985.
2. Bruckert, W. Vapor liquid contacting system and method. U.S. Patent 3,410,540, 12 November 1968.
3. Nye, J. O.; Gangriwala, H. A. Nye trays. Presented at the AIChE Spring National Meeting, 30 March 1992.
4. Sauter, J. R.; Hauser, R. P.; Harris, J. Fractionation trays. U.S. Patent 5,618,473, 8 April 1997.
5. Yeoman, N.; Griffith, V. E.; Hsieh, C.-L. Vapor liquid contact tray and downcomer assembly and method of employing same. U.S. Patent 5,480,595, 2 January 1996.
6. Binkley, M. J.; Thorngren, J. T.; Bonilla, J. A.; Gage, G. W. Downcomer-tray assembly and method. U.S. Patent 4,956,127, 11 September 1990.
7. Sloley, A. W.; Golden, S. W.; Martin, G. R. Why towers do not work. AIChE Spring National Meeting, 19-23 March 1995, Houston.
8. Binkley, M. J. Method of and apparatus for flow promotion. U.S. Patent 5,192,466, 9 March 1993.

About the Author:

Andrew Sloley is a consultant in distillation and troubleshooting. He worked as a troubleshooter and consultant for Glitsch, Inc. from 1990 to 1995 and for an engineering company between 1995 and 1999. Previously, he worked as a process engineer in technology development and application for Exxon Chemicals. His experience covers a wide range of petroleum refining and petrochemical areas. He has authored or co-authored over 100 publications and conference papers. Papers have appeared in Oil and Gas Journal, Hydrocarbon Processing, Petroleum Technology Quarterly, Chemical Engineering Progress, Hydrocarbon Technology International, National Engineer, and others. Conference papers have included presentations at the National Petroleum Refiners Association, American Institute of Chemical Engineers, American Society of Mechanical Engineers, Japan Society of Mechanical Engineers, Chemical Engineers Australia, and others. He currently acts as a consultant to a variety of companies in the area of troubleshooting and distillation. Other current work includes both engineer and operator training for distillation operations, design, and troubleshooting. Sloley has a bachelor's degree in chemical engineering from the University of Tulsa, and is a registered professional engineer in the State of Texas. He resides in College Station, Texas and can be reached at asloley@distillationgroup.com or tel: 979-764-3975 (www.distillationgroup.com).