Vanquish Vacuum Distillation Difficulties

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The two-stage steam ejector system for our vacuum distillation column causes us numerous problems. Startup is difficult because of poor vacuum control — especially during the summer when our cooling-tower water runs warmer than usual. When this occurs, we cut the tower vacuum but that only gives modest improvement. Moreover, ever since we began using higher ratios of high-sulfur Canadian crude, we've had corrosion and erosion issues. Recently, the motive steam nozzle split and leaked, causing us to pull air instead of tower vapor. We swapped the carbon steel ejectors for Type-316 stainless steel ones but still experience erosion in the ejector diverging nozzle, converging diffuser and even in the outlet diffuser. We're also wondering whether we should capture more of the hydrocarbon vapors now lost to the thermal oxidizer. How can we improve this operation? What's behind our corrosion problem? Should we be concerned about the economics of the thermal oxidizer?

I'm going to interpret "cutting the vacuum" to mean that you intend to reduce load to the second-stage ejector by throttling steam to the first-stage ejector. This will change first-stage-ejector performance. (A small operating envelope is available for this change.) Less steam going to the first-stage inter-condenser decreases its duty, enabling the condenser to reduce load on the second stage.

On systems like this, the second-stage suction pressure is set by the interaction of the second-stage capacity and the condensation pressure of water at the approach temperature possible in the first-stage inter-condenser. In well-built systems, the approach temperature normally sets the limits. The approach temperature limit can create a problem if the condensation pressure in the first condenser rises above the maximum working discharge pressure allowable on the first-stage ejector. No easy answer may be available for this.

Some steps might be possible: check that the isolation valve between the steam supply and the second-stage suction is really closed; make sure that no one has pinched back the water supply to the condensers in the winter; and evaluate installing a cooling-water booster pump.

At a differential pressure of 200–250 psig, even a small leak in the isolation valve between the steam system and the vacuum system will result in significant losses. An acoustic leak detector will quickly find small valve leaks. A quick check is surely worth the effort.

Plants may attempt to cut cooling water costs during the winter by pinching back on the cooling water supply. Lower cooling-water velocities cause exchangers to foul more rapidly. In the following summer, the fouled exchanger no longer can meet duty requirements. This is one service that never should have cooling water pinched back.

Vacuum ejector condensers are a critical service. The economic costs here probably justify stealing cooling water from elsewhere by installing a cooling-water booster pump. A water pump with relatively low head could add enough flow to simplify startup and improve summer operation.

More surface area will allow closer temperature approaches. Specially configured baffle arrangements in the condenser also may help. These more drastic solutions will require replacing the inter-condenser.

As far as erosion, its location provides a clue as to the cause, which normally is some combination of liquid droplets in the process suction or motive steam. Other possibilities include misaligned steam nozzles and ejector converging-diverging diffusers. Better de-entrainment separators can reduce liquid in the steam. (Significant advances have been made with cyclonic vapor/liquid separators in recent years. If the upstream water knockout is old, you may be able to improve this a lot.) Ensure these separators and the steam pressure control valve are installed close to the ejectors.

Hydrogen sulfide overhead results from thermal cracking. Higher hydrogen sulfide rates will correlate with higher rates of other cracking products. The cracking products increase gas volumes overhead. Higher gas volume, and velocity, overhead will raise liquid entrainment from the top of the column.

Process liquid removal presents more difficult problems. The only effective solution is to modify the upstream vacuum tower or upstream operation. Most of these towers use a spray liquid distributor for the top liquid. Conversion to a gravity feed (trough) distributor often will dramatically reduce liquid drop carryover. Wire-mesh and plate-type mist eliminators are mostly ineffective in this service.

Load to the thermal oxidizer is set by equilibrium in the final condenser. The only way to reduce the load is to make the after-condenser colder. You can achieve this either by reducing cooling water temperature or modifying the exchanger to get a closer approach temperature. Based on typical hydrocarbon recovery values, neither is likely to justify the cost of the modifications involved. If this has become a permit problem, you may have no choice.

Reducing non-condensable leaks and upstream cracked gas make will also reduce hydrocarbon losses in the final condenser. Fixing system leaks will help all parts of the system. Decreasing cracked gas make may require significant operating or equipment changes in the upstream vacuum heater or vacuum tower.
Andrew Sloley, principal process engineer
CH2M Hill, Bellingham, Wash.

As a consulting engineer who has been designing ejectors and systems for over 45 years, I have several comments. First, if the operating temperature of the cooling water is higher than the summer design temperature, the condenser pressure will increase, resulting in poor vacuum and unstable operation. By design, the design water temperature is the maximum allowable and the steam pressure is based on the minimum available.

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