The Distillation Group, Inc.

P.O. Box 10105, College Station, TX 77842-0105 USA Phone 979-764-3975info@distillationgroup.com Fax 979-764-1449

Troubleshooting Refinery Vacuum Towers

Presented at theAIChE Spring National Meeting

22-26 April 2001Copyright 2001 Andrew W. Sloley

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The Distillation Group, Inc.P.O. Box 10105

College Station, TX 77842-0105USA

[1]-(979)-764-3975[1]-(979)-764-1449 fax

info@distillationgroup.com

www.distillationgroup.com

Troubleshooting Refinery Vacuum Towers

Andrew W. SloleyThe Distillation Group, Inc.

PO Box 10105College Station, TX 77842-0105

USA

Presented at theAIChE Spring National Meeting

Session: New Frontiers in Refinery Fractionator Operation23-27 April 2001

Houston

Copyright Andrew W. SloleyFebruary 2001

IntroductionWith crude price fluctuations often compressing refinery margins, stable and efficient vacuum

tower operation is more critical than ever to refinery profits. Many refineries run up to five years withgood vacuum tower yields. Others have consistent problems getting past an eighteen month run. Majorsources of lost profits include coking, high pressure drops, internal leaks, and loss of vacuum. Simpletools, costing less than $200 each, used correctly can identify and track many common vacuum towerproblems. Systematic problem analysis coupled with standard stream analysis methods can identifymany others.

Knowing problems before a shutdown cuts maintenance costs. Unscheduled procurement andwork may cost as much as ten times (or more) than scheduled work[1]. Knowing what when and howa problem starts is key to solving it. Reliable operation increases overall plant profits. Ineffective trou-bleshooting leads to failed fixes and continuing losses.

Four case studies are shown. The first looks at causes of a coking wash bed. The second exam-ines internal leaks and their affect on heat removal. The third briefly shows an example of an externalleak and its impact on heat-transfer and yields. The fourth, a coked wash bed in a visbreaker vacuumtower, illustrates that the problems are not limited to crude vacuum towers. They also occur in vis-breakers, hydrocrackers, and other units.

Troubleshooting requires understanding how the process and the different equipment interact.Troubleshooters must know more than just how equipment functions in isolation. They must under-stand how entire systems work and how different types of equipment interact. Simple, common prob-lems should always be checked before attempting to use expensive, difficult to interpret, and time con-suming high technology troubleshooting tools. Most unit problems are simple in cause and can beidentified with effective use of field technique. Rapid problem identification cuts costs and increasesprofits.

Coked Wash Beds: A Continuing ProblemCoking wash zones have been the source of many vacuum unit shut downs. Some packed vac-

uum towers have five-year runs reliably. Others shut down for wash bed replacement every 18 months.For one refiner (the first case study), the flash zone pressure increased from 27 mm to 36 mm over atwo year run.

A simple, low-cost manometer allows for wash zone monitoring. An absolute mercury ma-nometer is accurate to within one-half mm of mercury pressure when used correctly[2]. A pressure sur-vey immediately after startup sets a base-line performance for the vacuum tower. The unit engineershould monitor the operation of the vacuum tower with periodic pressure surveys. If the pressure drop,for the same distillate yield, increases by two mm of mercury or more across a packed bed, the hascoked.

With the low liquid rates in the vacuum columns wash zone, pressure drop increases in thewash zone are nearly always caused by coking. A coked wash bed increases flash zone pressure, dropsdistillate yield, and eventually leads to black HVGO product. Increased pressure drop across the washsection increases residue entrainment. Increased carbon and metals from black oil loads the FCC cata-lyst, produces more FCC cracked gas, and drops FCC product quality.

Coked Wash Bed Shuts Unit Down

Problem History

The refiner replaced the existing wash oil spray header with a new one designed for lower flowrate to increase gas oil yields. At startup, the gasoil yield rose and the pressure drop was the same asbefore modifications. Unit operation for the first year seemed trouble-free. A pressure survey immedi-ately after startup set a base-line performance for the vacuum tower (Figure 1). Over the second year,the flash zone pressure rose from 18 mm of mercury to 27 mm of mercury (Figure 2). Cut pointdropped from 1052F (566C) to 1038F (559C). Distillate yield losses were costing approximately$1,600,000 per year. After two years the unit was shut down for cleaning.

When the unit shut down, no replacement grid had been ordered. Upon entry, the grid wasfound coked. The wash grid delivery time was going to be too long to wait to replace it. Rather thanreplacing the grid, the wash zone grid was cleaned in place with a high-pressure water lance from thetop. Grid is manufactured in shallow layers approximately 2-5/8 inches (67 mm) thick (Figure 3). Eachgrid layer is rotated from the layer below. A water lance cannot reach more than the top one, or per-haps two, layer(s).

Other equipment inspected during the turnaround included the overflash collector tray and thewash oil distributor. No obvious damage was seen on either.

After restarting the unit with the water-lanced grid, the pressure drop was even worse than be-fore! The pressure drop across the wash bed had increased from ten mm of mercury to 19 mm of mer-cury (Figure 4). Once exposed to oxygen, the coke had hardened and the water-lance debris blocked alarge part of the open area that had been available in the grid before the shutdown. Cutpoint droppedagain, to 1025F (552C).

Replacement grid was immediately ordered. As soon as the new grid was received, anothershutdown took place, the old grid removed and the new grid placed in the tower. If the pressure surveyresults had been understood or believed, replacement grid could have been ordered well in advance. Asecond shutdown would have been avoided. Avoiding the extra shutdown would have easily paid formany $200 manometers and pressure surveys.

First Fix

After the unit restarted with the clean grid, the wash rate was returned to the previous rate.Fully wet packing helps prevent coking. Many literature reports emphasize the importance of havingthe correct wash oil rate to keep the packing wet. While lacking many important details and grosslysimplifying the process analysis, the conclusion that many units have insufficient wash oil is correct.

Computer models can predict wash oil rates if done correctly. Nevertheless, troubleshootingstarts in the field. Correct data must be gathered and interpreted first. Successful unit revamps andeffective troubleshooting start with field data, not theoretical calculations.

The unit seemed to work correctly for the first fourteen months, then pressure drop surveysstarted showing that the flash zone pressure was rising. Over another fourteen months, the pressuredrop across the wash zone increased by six mm of mercury. The wash bed had coked again, with only asmall improvement in run length.

Equipment and the process do not exist separately. Equipment details count as much as processdetails. Process limits come from equipment limits. Not only must the wash rate be correct, it mustalso be distributed properly. Figure 5 shows a sketch of the type of spray header used. Spray nozzles ona pipe header distribute the liquid over the packed bed. To develop a proper spray cone, a five psi (34kPa) to 20 psi (138 kPa) pressure drop across the spray nozzle is required. Much below five psi (34kPa), the spray cone does not develop. Above 20 psi (138 kPa) the spray starts to form smaller dropletsthat entrain more easily.

A simple pressure gauge can check the operation of a spray header. Figure 6 shows the pressurereading obtained by putting a gauge downstream of the wash oil control valve. The pressure gauge read11 psi (76 kPa) at five feet above grade. This must be adjusted to the spray header elevation by:

After adjusting for height, the spray header pressure drop is only one psi (seven kPa). When checkingthe nozzle details, for the new flow rate the pressure drop should have been 35 psi (240 kPa). Some-thing was wrong with the spray header.

At the second unit shutdown, the spray header was inspected and two things found. First, thewrong size spray nozzles were on the header. The nozzles had approximately three times the capacitythey should have had. Second, many of the flange gaskets had been left out (Figure 7). Instead offorming spray cones, the liquid was just pouring onto the packed bed in a series of solid, small diame-ter jets (Figure 8). Just enough liquid was getting onto the wash bed from condensing on the undersideof the HVGO collector, by entrainment from the flash zone, and spraying out of the flanges withoutgaskets to coke up the bed.

The spray header nozzles were replaced with ones the correct size and gaskets were installed onall flanges. After this shutdown, the unit has been working without coking the wash bed. Operationhas proved successful at the lower wash oil rate.

Revamp limited by vacuum tower heat removal

Problem History

A refiner completed a major revamp to increase capacity and run new, heavier crudes. After therevamp, projected crude unit yields could not be obtained. The crude unit was limited by heater duty.The oil could not get to the needed temperature. Theoretical analysis of the problem showed that thecrude preheat temperature was 40F (22C) colder than expected. As crude heat integration exchangers

2.31feet of elevationdifference specific gravity of fluid atconditions

Static Head

=

often suffer from dramatically higher fouling than many engineering standards assume, the initial con-clusion was that the crude preheat exchangers were fouling more than expected. Often, newer, heaviercrudes have high fouling factors. Heavier crudes also contribute to asphaltene precipitation whenmixed with lighter crudes. This can dramatically increase exchanger fouling.

Rather than accepting a preliminary conclusion, management insisted that a plant test anddata analysis be done to verify this before further detail engineering began on crude train modifica-tions.

A plant test was run and data gathered. Reduced preheat to the atmospheric column has twomajor affects. First the amount of AGO recovered drops. This decreases high-level AGO heat availablefor preheat. Second, the lighter material gets into the LVGO, decreasing the LVGO temperature. Nor-mally, LVGO rejects heat to cooling water and air, so this has minimal direct impact, as long as theLVGO can handle the increased duty.

Decreased preheat duty from AGO rundown, reduces the crude tower operating temperatureeven more. The decreased crude tower operating temperature then drops more AGO into the vacuumtower feed (Figure 9).

Detailed test run data review and modeling showed that the HVGO was cooler than expected.Reduced HVGO draw temperature has an even bigger impact than AGO rundown duty losses.

The HVGO draw temperature was 50F (28C) lower than expected. Figure 10 shows the basicdata around the vacuum unit. Drawing material balance envelopes around the vacuum tower andchecking the heat balance shows that 2,400 bpd (380 m3/day) of LVGO is being condensed but is notbeing drawn as LVGO product (Figure 11). Instead, it comes out with the HVGO product. The re-duced LVGO temperature was the major reason feed preheat to the crude unit could not be attained.This was costing the refiner three million dollars a year.

Fixing the Vacuum Tower

Equipment and the process do not exist separately. Equipment details count as much as processdetails. Process problems come from equipment limits. Many reasons cause LVGO to leak into HVGO:the collector can leak, the draw nozzle can be too small[3], the collector can be damaged. In one nota-ble case, an HVGO collector was damaged by using a jackhammer to remove coke from it.

Originally, the vacuum tower had bubble cap trays. Approximately 15 years ago most of thebubble caps had been replaced with structured packing and grid. However, new collectors were not in-stalled at that time. Three bubble cap trays were modified to act as collectors. Modifications were donein the field to change the bubble cap trays to total draw trays. Figure 12 shows the modifications to thedraw tray sumps. A comparison with a regular collector tray sump is shown.

Rapid inspection shows a major problem. The sump is not fully sealed. At low pumparoundrates this may not matter, the height of liquid above the nozzle is enough to get the pumparound plusproduct out the draw even though the sump is not sealed. As pumparound rates increase, the liquidlevel in the sump rises until the sump overflows, spilling LVGO into the HVGO.

As a quick check, the HVGO pumparound rate increased to its maximum, and the LVGOpumparound rate decreased. A dramatic increase was seen in HVGO draw temperature when LVGOpumparound rate dropped slightly. For a temporary fix, HVGO rate was set to its maximum (it had thesame problem with liquid overflow as the LVGO collector) and LVGO return temperature minimizedto attempt to keep the LVGO pumparound rate as low as possible. This helped the unit most of thetime, but the plant still suffered from weekly upsets when the LVGO tray overflowed. Additionally, thecollector trays had very high pressure drops compared to properly designed collectors. The modifiedbubble cap trays imposed an extra three mm of mercury pressure drop. For a packed vacuum columnthis has a significant yield affect.

The solution to this problem was putting in correctly designed LVGO and HVGO collectortrays at the next turnaround. The new collectors solved most of the problems with preheat. Only minorpreheat train changes were needed. Preheat changes are very expensive because of the cost of pipingand plot plan problems. Tower internal solutions have no plot plan problems.

No complex computer models or high tech methods were required. Simple mass-balance andheat-balance calculations were all that was needed to identify the vacuum tower problems. Review ofthe drawings identified the exact cause. Quick field verification showed that the problem identified wasthe real cause of the preheat loss.

Sudden Vacuum Loss Drops Yields

Problem Background

A refiner experienced a sudden loss of vacuum in a dry vacuum tower operating with an over-head pressure of 10 mm Hg. Overhead pressure had risen to 20 mm Hg. Substantial yield losses werebeing incurred every day. Figure 13 shows the overall unit with a heat and material balance boundary.

Sources of Vacuum System Load

Figure 14 shows the major sources of unexpected vacuum system load. Vacuum system loadchanges occur from either different (or additional) material entering the system or by hydrocarboncracking inside the system. This includes both intentional sources and environmental sources. Inten-tional sources are material added to the system with the full knowledge that the material will go to thevacuum system. The major intentional sources are usually stripping steam added to the vacuum towerboot and velocity steam added to the heater coils. Environmental sources are streams that the plantattempts to minimize because they serve no useful purpose, but only consume vacuum system capac-ity: increasing capital requirements and operating costs.

Environmental sources include: Vacuum unit feed changes caused by upstream (atmospheric tower) damage, often in the

stripping section. Increased heater coking. Improperly metered increases in velocity steam or stripping steam. Heat exchanger leaks from heat integration circuits. Vacuum tower coking. Air leaks.All of these areas can create problems rapidly from apparently small changes in equipment per-

formance.

Vacuum Unit Feed Changes

Atmospheric stripping section damage is one of the most common sources of added vacuumsystem load. Even small amounts of damage to the stripping section can add large amounts of lightmaterial to the vacuum tower feed. This loads the vacuum ejectors, causing higher vacuum systempressures. Higher vacuum system pressures reduce HVGO yield and increases residue yield. Profits arelost.

Increased Heater CokingHydrocarbon cracking in the heater breaks forms coke plus cracked gas. Cracked gas may con-

tain hydrogen sulfide, methane, ethane, ethylene, and other light compounds. Heater cracking ratesdepends upon mass flux, heater temperature profile, heat flux profile, and heater history. Heater design

dramatically affects coking rates for the same conditions. A well designed, operated, and maintainedheater may have low cracking rates at the same conditions a poorly designed heater is inoperable.Heater design and operation is critical to profitable vacuum unit operation.

Once coke is formed in heater tubes, additional cracking and coke formation is even easier.Coke makes more coke. Coke formation makes cracked gas as well.

Improperly Metered SteamFlow meter drift can add much additional steam to the vacuum heater or vacuum tower strip-

ping section. Additional steam adds load to the ejectors. The higher ejector load drops the system pres-sure.

Heat Exchanger Leaks from Heat Integration CircuitsHeat exchange in the heavy vacuum gas oil (HVGO) and light vacuum gas oil (LVGO) circuits

condenses the vacuum tower product. Most units integrate much of the heat removal with crude pre-heat. A few integrate with steam generation or other units. In either case, leaks in the heat removalexchangers leak from the heat removal utility into the vacuum process side.

Crude contains light material that loads up the vacuum system. Boiler feed water preheat leaksor steam generator leaks adds water, and hence steam load, to the system. Both make the ejectors workharder.

Vacuum Tower CokingVacuum tower cracking most often occurs in the boot, collector trays, or in the vacuum wash

zone. Rarer, but still possible, is cracking in the vacuum tower stripping section. Cracking in the collec-tor tray liquid or in the wash zone results in a coked vacuum tower. In addition to the cracked gas loadincrease, coked vacuum towers can produce black products and dramatically lower yields. Cracking inthe boot can coke up the tower draw and shut the unit down as well. Cracking of liquid in the boot isthe most common source of cracked gas in the vacuum tower. Quench addition to the boot can controlthis rate and unload the vacuum system.

Noticeable changes in cracked gas rate from collector tray, wash zone, or stripping sectioncoking indicate critical problems in the vacuum tower. Coke formed by cracking in these areas buildsup inside the tower rapidly. Coked wash sections and collectors increase tower pressure drop, reduceyields, and make black products. Cracking on the stripping section trays plugs the bottom of the tower.Liquid entrainment from the stripping section increases. Proper equipment design and installation canprevent problems.

Air LeaksLoose flanges increase leaks into the system. Increased leakage increases the vacuum system

load. System pressure rises and yields drop.

Finding the Problem

Systematic approaches help troubleshooting. The root causes of most unit problems are simple,even if they are difficult to find. Often, too much attention is paid to rare and difficult to find prob-lems. Simple sources of problems are not checked thoroughly enough before they are eliminated fromfuture consideration. The attraction of working on something new, unique, or rare (i.e. exciting) luresmost engineers past the basics without sufficient consideration given to simple problems.

Good field technique, understanding of the process, and application of engineering fundamen-tals identifies the vast majority of problems. Troubleshooting should check the easiest, cheapest, mostlikely, and quickest to find problems first.

Load on the first ejector in a steam jet vacuum system sets the suction pressure. Most refineryand chemical plant vacuum systems are critical ejector systems: the ejector discharge pressure is morethan twice the ejector inlet pressure. Figure 15 shows a typical vacuum system ejector curve.

In troubleshooting any chemical process system, one of the first steps should be to draw a heatand material balance boundary around the system and check how the entering and leaving streamshave changed. Figure 16 shows a three-stage ejector system, its heat and material balance boundaryand identifies the entering and exiting streams.

Drawing the heat and material balance around the vacuum tower plus the vacuum system(Figure 17) clearly shows that if the total load going to the system has increased, the load change mustalso show up in the streams leaving the system. The slop oil rate must change, the sour water rate mustchange, or the vent gas rate must change. However, vacuum systems may be sensitive enough to loadchanges that rate changes too small to easily see may still cause operating problems.

Direct Identification of the Leak

Checking the exiting streams showed a slop oil rate 75% higher than normal operation. Distil-lation tests showed that a large amount of naphtha, kerosene, and diesel was in the stream. If an up-stream upset had damaged the atmospheric tower stripping section most of the additional light mate-rial would be diesel and a small amount of kerosene. The large amount of naphtha and kerosene clearlyindicated that crude was leaking into the vacuum tower.

The unit was dropped to a lower capacity and crude preheat exchangers isolated in groups,then individually. After several days of testing, the leaking exchanger was isolated and the bundlepulled for repair. After the bundle was pulled, the unit was restored to approximately 90% of capacityat desired yields while repairs took place.

Coking in Refinery Main Fractionators

Thermally unstable oils and coking

Many refinery main fractionators process thermally unstable oils. Common services include:1. Atmospheric crude columns2. FCC main fractionators3. Gas oil crude columns4. Vacuum preflash columns5. Vacuum crude columns6. Delayed coker main fractionators7. Fluid coker main fractionators8. Visbreaker atmospheric columns9. Visbreaker vacuum columns10. Residue hydrocracker atmospheric columns11. Residue hydrocracker vacuum columns

While services differ between units and plants, the list has been sorted into a generally least severe togenerally most severe order.

Reliable operation with thermally unstable oils requires a great care with mechanical details.Coking is a product of time, temperature, and thermal instability. Mechanical details that create small

liquid pockets or films with long residence times initiate coke formation. Once started, coking maycontinue until major problems develop.

Grid versus Packing in Wash Services

Any type of packing can coke in wash zone service. No clear evidence exists on the superiorityof either grid or structured packing in this service. Vapor and liquid distributor design, fabrication, andinstallation are so much more important that minor differences between grid and structured packingcan be ignored.

In general, grid will require a deeper bed than structured packing for the same de-entrainmenteffectiveness. For a given degree of wash bed effectiveness, pressure drop across grid or structuredpacking will be approximately equal. Grid has been used more often in this service because it has beenavailable for a longer time than structured packing.

Random packing should not be used in refinery main fractionator wash service. Randompacking inevitably has parts of the packing that hold liquid for long periods of time. Long residencetimes increase the risk of coked beds. Figure 18 and Figure 19 show drawings of typical, modern ran-dom packings. Random packing fills a vessel randomly. Some packing will always lie with spots whereliquid can have long residence times. This is especially true in low liquid rate services. Wash zones arelow liquid rate services. Long residence times, high temperatures, and thermal instability of the oil leadto coking.

In contrast, Figure 20 shows a drawing with elements of typical, modern structured packing.The surface can drain freely. Coking tendency is reduced.

Wash Zone Liquid Rates

To keep terminology clear, we will use the following terms as shown in Figure 21: Wash oil: the oil sent to the top of the wash bed to clean entrainment from the wash bed. Overflash: the oil that comes from the bottom of the wash bed that is the residue of the

wash oil used. Slop wax: the oil from the collector tray immediately below the wash bed. (This term

comes from old-time lubricant column operation and is not strictly applicable to fuels vac-uum column operation. However, industry standard usage accepts its application to fuelsvacuum columns.)

Condensate: liquid condensed on the underside of the collector tray that falls (usually)back into the flash zone.

The obvious question looking at Figure 21 is why do we make a distinction between overflash and slopwax? Figure 21 is not complete. We have not considered entrainment. The purpose of the wash zone isto remove entrainment from the feed. Entrained oil makes the products black. A very small amount ofentrainment can make a product D 8 color.

We normally consider entrainment a very small quantity. This is not always true. At very lowwash rates and high vapor velocities in the column, entrainment can reach a significant fraction of theliquid on the collector tray. In some units, entrainment may be nearly 100% of the slop wax. Figure 22expands the definitions from Figure 21 to include entrainment.

Obviously, with a functioning wash zone the entrainment never reaches the product above thewash bed. Therefore, the slop wax liquid is:

Slop wax Overflash Entrainment= +

Measured slop wax is never equal to overflash.

Care must be taken with data interpretation to make sure that the overflash rate is determinedwhen deciding if a wash bed has liquid coming out the bottom of it. Common methods of determiningoverflash rates include metals and asphaltene balances around the feed and slop wax. Other techniquescan be used as well. It is critical to avoid confusing slop wax rates with overflash.

Visbreaker Operation Limited by CokingVisbreaker products are thermally unstable oils. At the high temperatures in wash zones they

readily coke. Extreme attention to mechanical design details must be included to eliminate dead spotswhere coking can occur.

A refinery visbreaker had problems with high pressure drops and coked wash beds over a pe-riod of years. After several turnarounds, a thorough attempt to understand and solve the problemstarted.

Current Operation

The main causes of poor quality HVGO products from refinery main fractionators are cokedwash beds, poor liquid distribution to the wash bed, and poor vapor distribution to the wash bed.These causes are related. Poor distribution to a wash bed, of either vapor or liquid, leads to coking.

Coking partially blocks the wash bed. Vapor velocity increases due to the lower cross sectionarea open. The higher vapor velocities increase entrainment. Entrainment carries black oil from thefeed entry (flash zone) up to the HVGO product. Black HVGO results. This severely affects down-stream operation and product quality. Your D8 color is typical for a coked wash zone.

Data showed a pressure drop of 28 mm Hg across the tower before shutting down (Figure 23).This is a very high pressure drop for a normally operating vacuum tower. Unless collectors have excep-tionally high pressure drops and the grid beds are very deep, a typical pressure drop in this servicewould be 12-18 mm Hg across the tower. High pressure drops occur across coked beds.

The process operation was also checked. A commonly used number for grid or structuredpacking wash zone liquid rates is 0.15 gpm/ft2 (0.367 m3/hr-m2) of tower cross-section area at theminimum liquid wetting point. For wash zones, the minimum liquid wetting rate is found on the bot-tom of the bed. The rate the data shows is 0.097 gpm/ft2 (0.237 m3/hr-m2) of slop wax. The observedrate was low and is a probable contributor to coking.

While incomplete, the available evidence supported the conclusion that the wash bed wasbadly coked. Coked wash beds lead to poor product qualities.

Work Recommendations

The wash bed had to be replaced. Whatever caused the bed to coke in the first place had to beidentified and fixed. This is often a complex activity. The root cause of coking problems may not beapparent. Many units have been fixed only to have coking occur again. Unit reliability and productquality depends upon identifying and fixing the real problem.

Both grid and packing can coke. No clear evidence exists on the superiority of either grid orstructured packing in this service. Vapor and liquid distributor design, fabrication, and installation areso much more important that any minor differences between grid and structured packing can be ig-nored. The mechanical support structure and collector design must also be reviewed to eliminate deadspots where liquid can sit with a long residence time. Long residence times increase the risk of cokedtowers.

The process was checked and modifications designed for the wash oil system.

Shutdown Observations and Repair

The unit was shut down. The wash bed and the collector tray were coked. The entire wash bedwas coked solid and large quantities of coke had accumulated on different parts of the collector. Modi-fications were made to the wash oil system, collector, and mechanical support structure. The unit wasrestarted and has operated normally. No evidence of coking has yet been seen.

ConclusionsMany plants have very good experience and routinely run for five years without wash bed

coking. Others coke as often as every 18 months. Understanding the process and correct mechanicaldesign, fabrication, and installation is required for reliable wash zone operation. The hotter the opera-tion and the less stable the oil, the more important every detail becomes. Standard design approachesbased on old-time, low-severity services fail to perform acceptably in severe services.

Simple instruments, correctly used, identify many refinery vacuum column problems rapidlyand at minimum cost. Absolute pressure manometers and heat and material balances are valuable, in-expensive tools. Accurate data and good field technique identifies problems better than back-office cal-culations and engineering standards books.

Systematic troubleshooting using basic engineering concepts with heat and material balanceenvelopes identify and locate many other unit problems. Simple, common problems should always bechecked before attempting to use expensive, difficult to interpret, and time consuming high technologytroubleshooting tools. Most unit problems are simple in cause and can be identified with effective useof field technique. Rapid problem identification cuts costs and increases profits.

Disclaimer

No performance, suitability for use, or lack of suitability for use for any given process service isimplied to any particular model or brand of packing by these comments. Figures used have been usedas illustrative of generic classes of equipment.

Figure 1

Pressure survey of tower at start of run

vacuum residue

feed

wash

hvgo

lvgo

HVGO PA

LVGO PA

to Vacuum System

pressure, mmHg

15

14

13

12

11

16

18

Figure 2

Pressure survey of coked tower

vacuum residue

feed

wash

hvgo

lvgo

HVGO PA

LVGO PA

to Vacuum System

pressure, mmHg

25

27

15

14

13

12

11

Figure 3

Typical grid used in many vacuum tower wash zones

Figure 4

Pressure survey of coked tower: after water lance cleaning

LVGO PA

HVGO PA

vacuum residue

feed

lvgo

hvgo

to Vacuum System

wash

pressure, mmHg

15

14

13

12

11

34

36

Figure 5

Typical wash zone spray distributor

Figure 6

Spray header pressure survey

LVGO PA

HVGO PA

vacuum residue

feed

lvgo

hvgo

to Vacuum System

15wash

11

pressure, psiaelevation 5ft (1.5m)

pressure, mmHgpressure, mmHg

elevation 32ft (9.7m)

Figure 7

Spray header with missing gaskets and loose flanges

Figure 8

Spray nozzle comparison: improper versus proper cone development

missing gaskets and/or loose flanges

missing gaskets and/or loose flanges

missing gaskets and/or loose flanges

spray with a properly developed spray cone

spray with insufficient pressure drop to

develop cone

Figure 9

AGO yield spiral

decreased AGO preheatproblem

lower heater feed temperature

lower heater outlet temperature

decreased AGO yield

Figure 10

Vacuum tower yield and temperature data

LVGO PA 54900 bpd36.5 M btu/hr

HVGO PA 43700 bpd49.1 M btu/hr

feed

lvgo 9100 bpd

hvgo 14800 bpd

to Vacuum System

wash

411 F

612 F

Figure 11

Vacuum tower heat and material balance check

411 F

612 F

HVGO PA 43700 bpd49.1 M btu/hr

feed

wash

LVGO PA 54900 bpd36.5 M btu/hr

hvgo 14800 bpd

(lvgo 11500 bpd)lvgo 9100 bpd

to Vacuum System

(hvgo 12400 bpd)

(calculated values)

Figure 12

Modified sumps when converting from a tray to a packed tower

original trays with sump

modified tray with sump

sump not sealed\can overflow at high liquid

rates

collector tray sump

(vapor risers and bubble caps not shown for

clarity)

Figure 13

Entire system heat-balance and material-balance envelope

Figure 14

Sources of vacuum system load

Figure 15

Typical vacuum ejector operating curve, first stage of an ejector system

8

10

12

14

16

18

20

22

24

26

28

Water vapor equivalent load, mass/hr

Maximum working discharge pressure: 125 mm HgMinimum motive steam pressure: 150 psig

Suction pressure, mmHg

Figure 16

Vacuum system with heat and material balance boundary

air leaks

load from Vacuum Tower

Vacuum System HMB Boundary

motive steam

vent gas

slop oil

sour water

cooling water

cooling water

Figure 17

High slop oil rate indicating a leaking crude preheat exchanger

Figure 18 [4]

Random packing with locations for liquid to have a long residence time

Figure 19 [5]

Random packing with locations for liquid to have a long residence time

Figure 20 [6]

Structured packing with few locations for liquid to have a long residence time

Figure 21

Flash zone terminology

Wash Bed

wash oil

slop wax

feed

Flash Zone

Slop Wax

Collector

overflash

condensate

Figure 22

Flash zone terminology with entrainment included

Wash Bed

wash oil

slop wax

feed

Flash Zone

Slop Wax

Collector

overflash

condensate

entrainment

Figure 23

Visbreaker operation before shutdown

lvgo PA

to Vacuum System

lvgo draw

hvgo PA

hvgo draw (black)

wash oil

(100-130 m3/h)

slop wax

(25 m3/h)

visbreaker bottoms

feed

10-14 mm Hg

38-42 mm Hg

3200 mm diameter

11600 mm diameter

4300 mm diameter

Wash Bed

HVGO Bed

Fractionation Bed

LVGO Bed

References

[1] Sloley, A.W. Reducing the danger of maintenance exposure. Petroleum Technology Quarterly,1998Spring: 59-65.[2] Sloley, A.W. The simple things. Hydrocarbon Processing. 1999 August: 17.[3] Sloley, A.W. Dont get drawn into distillation difficulties. Chemical Engineering Progress,1998 June:63-78.[4] From Strigle, R. F., Jr. and Porter, K. E. US Patent 4,303,599 Tower packing. 1 December 1981.[5] From Nutter, D. E. US Patent 4,576,763 Packings for gas-liquid contact apparatus. 18 March1986.[6] From Chen, G.; Kitterman, B. L.; Axe, J. R. US Patent 4,604,247 Tower packing material andmethod. 5 August 1986.